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TABLE OF CONTENTS
INDEX TO FINANCIAL STATEMENTS

As filed with the Securities and Exchange Commission on November 4, 2005

Registration No. 333-127517

SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

Amendment No. 2
to
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
(State or other jurisdiction of
incorporation or organization) 1389
(Primary Standard Industrial
Classification Code Number) 54-2091194
(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)

Copies to:
Andrews Kurth LLP 600 Travis, Suite 4200 Houston, Texas 77002 (713) 220-4200 Attn: David C. Buck	Vinson & Elkins L.L.P. 2300 First City Tower, 1001 Fannin Houston, Texas 77002 (713) 758-2222 Attn: Thomas P. Mason

        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

        If delivery of the prospectus is expected to be made pursuant to Rule 434, please check the following box. 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 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 November 4, 2005

12,500,000 Shares

Basic Energy Services, Inc.

Common Stock

        This is an initial public offering of shares of common stock of Basic Energy Services. We are selling 5,000,000 shares of common stock, and the selling stockholders are selling 7,500,000 shares of common stock. We will not receive any of the proceeds from the shares of common stock sold by the selling stockholders. One of the selling stockholders owns a majority of the shares of our outstanding common stock and is also an affiliate of Credit Suisse First Boston, one of the underwriters of this offering.

        Prior to this offering, there has been no public market for our common stock. The initial public offering price of our common stock is currently expected to be between $                     per share and $                    per share. Our common stock has been approved for listing on The New York Stock Exchange under the symbol "BAS," subject to official notice of issuance.

See "Risk Factors" beginning on page 10 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.

	Price to Public	Underwriting Discounts and Commissions	Proceeds to Basic Energy Services	Proceeds to Selling Stockholders
Per Share	$	$	$	$
Total	$	$	$	$

        To the extent that the underwriters sell more than 12,500,000 shares, the underwriters have the option to purchase up to an additional 1,875,000 shares from the selling stockholders at the initial public offering price less the underwriting discount.

        The underwriters expect to deliver the shares of common stock against payment in New York, New York on or about                          , 2005.

Goldman, Sachs & Co. Credit Suisse First Boston

Lehman Brothers

UBS Investment Bank

Deutsche Bank Securities

Raymond James

RBC Capital Markets

Prospectus dated                          , 2005

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

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. Unless the context otherwise requires, these terms also refer to our predecessor entity and its subsidiaries prior to our holding company restructuring in January 2003, which is described in "The Company."

Dealer Prospectus Delivery Obligation

Until              , 2005 (25 days after the commencement of the offering), all dealers that effect transactions in these securities, whether or not participating in this offering, may be required to deliver a prospectus. This is in addition to the dealers' obligation to deliver a prospectus when acting as an underwriter and with respect to unsold allotments or subscriptions.

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Prospectus Summary

This summary highlights information contained elsewhere in this prospectus. You should read the entire prospectus carefully, including the risks discussed in the "Risk Factors" section, the historical consolidated financial statements and notes to those financial statements. This summary may not contain all of the information that investors should consider before investing in our common stock. Unless otherwise indicated, all numbers of shares and per share amounts give effect to a 5-for-1 stock split effected as a stock dividend on September 26, 2005. Unless we specifically state otherwise, the information in this prospectus also does not take into account the sale of up to                   shares of common stock, which the underwriters have the option to purchase from the selling stockholders to cover over-allotments. 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, Louisiana and in 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 over 10% of the overall available U.S. fleet, with our two larger competitors controlling approximately 31% and 18%, respectively, according to the Association of Energy Service Companies. We maintain a strong market share position based on the number of available well servicing rigs in several of our operating areas, including 21% in West Texas, 19% in the Ark-La-Tex region and 15% in the Texas Gulf Coast region as of June 2005. Since the beginning of 2001, we have expanded our asset base from $53.0 million of total assets as of December 31, 2000 to $367.6 million of total assets as of December 31, 2004 and increased our revenues from $56.5 million in 2000 to $311.5 million in 2004.

        We derive a majority of our revenues from services supporting production from existing oil and gas operations. Demand for these production-related services, including well servicing and fluid services, tends to remain relatively stable, even in moderate oil and gas price environments, as ongoing maintenance spending is required to sustain production. As oil and gas prices reach higher levels, demand for our production-related services generally increases as our customers engage in more well servicing activities relating to existing wells to maintain or increase oil and gas production from those wells. The utilization rate for our fleet of well servicing rigs increased from approximately 60% in 2002 to 78% in 2004 and 87% for the first six months of 2005. 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 for the first six months of 2005) currently operates our fleet of over 300 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

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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 (30% of our revenues for the first six months of 2005) currently utilizes our fleet of over 400 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 (12% of our revenues for the first six months of 2005) currently operates our fleet of 37 pressure pumping units, 20 air compressor packages specially configured for underbalanced drilling operations and 11 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.



•

Well Site Construction Services. Our well site construction services segment (10% of our revenues for the first six months of 2005) 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 many smaller competitors owning approximately 1,000 well servicing rigs. We have led recent consolidation of this industry by acquiring regional businesses and assets in 35 separate acquisitions from the beginning of 2001 through June 30, 2005. We plan to continue participating in the consolidation of our industry after the completion of this offering by selectively acquiring additional businesses and assets that complement and expand our existing service offerings and geographic footprint. However, we cannot assure you that we will be able to complete such acquisitions.

Industry

        Demand for services offered by our industry is a function of our customers' willingness to make expenditures to explore for, develop and produce hydrocarbons in the United States, which in turn is affected by current and expected levels of oil and gas prices. As oil and gas prices have rebounded beginning in early 1999, total expenditures for all U.S. exploration and production activities (including offshore activities that we do not serve) have increased to an estimated $56 billion in 2003 and $62 billion in 2004 and are expected to reach $66 billion in 2005 according to Oil & Gas Journal.

        Increased expenditures for exploration and production activities generally involve the deployment of more drilling and well servicing rigs. The number of active rigs, also known as the rig count, serves as an indicator of demand for our services. According to Baker Hughes, the U.S. land-based drilling rig count increased approximately 36% from year-end 2002 to year-end 2003, and 11% from year-end 2003 to year-end 2004. In addition, the U.S. land-based workover rig count

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increased approximately 13% from year-end 2002 to year-end 2003, and 10% from year-end 2003 to year-end 2004.

        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.

        We expect more spending growth in the well servicing and fluid services markets to come from independent exploration and production companies, which represent over 90% of our revenue. 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.

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 300 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 63 of our rigs are either 2000 model year or newer, or have undergone major refurbishments during the last four years. As of June 30, 2005, we have taken delivery of 19 newbuild well servicing rigs since October 2004 as part of a 54-rig newbuild commitment. The remainder of these newbuilds will be delivered prior to the end of May 2006. Approximately 98% of our fleet was active or available for work and the remainder was awaiting refurbishment at June 30, 2005.

        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, Louisiana and the Rocky Mountain states. We operate in states that accounted for approximately 60% of the more than 900,000 existing onshore oil and gas wells in the 48 contiguous states and approximately 70% of onshore oil and gas production in 2004.

        Diversified Service Offering for Further Revenue Growth.    We believe our range of well site services provides us a competitive advantage over smaller companies that typically offer fewer services. 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

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controls. Below our corporate level, we operate a decentralized operational organization comprised of seven regional managers and more than 60 local managers responsible for managing our operations. 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.

        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. 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.

        Our strategies could be affected by any of the risk factors described in "Risk Factors" beginning on page 10.

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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

        During October 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 $3 million in cash. The cash used to acquire Oilwell Fracturing Services was primarily from borrowings under our senior credit facility.

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The Offering

Common stock offered:
	By us	5,000,000 shares.
	By the selling stockholders	7,500,000 shares (9,375,000 shares if the underwriters' over-allotment option is fully exercised).
	Total	12,500,000 shares (14,375,000 shares if the underwriters' over-allotment option is fully exercised).
Common stock to be outstanding after the offering		shares.
Common stock owned by the selling stockholders after the offering		shares (               shares if the underwriters' over-allotment is fully exercised).
Use of proceeds		We estimate that our net proceeds from the sale of the shares offered by us, after deducting estimated expenses and underwriting discounts and commissions, will be approximately $93.2 million. We plan to use $70.0 million of our net proceeds from this offering to repay a portion of the term loan under our credit facility. We will use an estimated $          million to repurchase an aggregate of up to 167,583 shares from ten officers at the initial public offering price, less underwriting discounts and commisions, for the purposes described in "Use of Proceeds." We will use the remainder for working capital and general corporate purposes.
		We will not receive any of the proceeds from the sale of shares of our common stock by the selling stockholders. One of the selling stockholders owns a majority of the shares of our outstanding common stock and is also an affiliate of Credit Suisse First Boston, one of the underwriters of this offering. See "Risk Factors — Risks Related to Our Relationship with DLJ Merchant Banking," "Use of Proceeds" and "Underwriting."
NYSE symbol		"BAS"
Risk Factors		See "Risk Factors" beginning on page 10 of this prospectus for a discussion of factors that you should carefully consider before deciding to invest in shares of our common stock.

The number of shares of common stock that will be outstanding after the offering includes an aggregate of 837,500 shares of restricted common stock issued to officers and key employees under our Second Amended and Restated 2003 Incentive Plan (our "2003 Incentive Plan") that are subject to vesting.

        The number of shares of common stock that will be outstanding after the offering excludes:

•

up to 4,350,000 shares that may be issued upon the exercise of warrants held by affiliates of DLJ Merchant Banking Partners III, L.P. and its affiliated funds, or DLJ Merchant Banking;



•

2,435,800 shares issuable upon the exercise of options outstanding as of June 30, 2005 under our 2003 Incentive Plan; and



•

an aggregate of 1,726,700 shares of common stock reserved and available for future issuance as of June 30, 2005 under our 2003 Incentive Plan.

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Summary Historical Financial Information

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

			Year Ended December 31,									Six Months Ended June 30,
			2002 (restated)			2003 (restated)
									2004			2004			2005
												(unaudited)
			(dollars in thousands, except per share data)
Statement of Operations Data:
Revenues:
	Well servicing		$	73,848		$	104,097		$	142,551		$	66,098		$	98,650
	Fluid services			34,170			52,810			98,683			45,006			60,839
	Drilling and completion services			733			14,808			29,341			12,116			24,276
	Well site construction services			—			9,184			40,927			18,645			19,866
		Total revenues		108,751			180,899			311,502			141,865			203,631
Expenses:
	Well servicing			55,643			73,244			98,058			45,416			61,464
	Fluid services			22,705			34,420			65,167			29,743			39,119
	Drilling and completion services			512			9,363			17,481			7,057			12,731
	Well site construction services			—			6,586			31,454			14,384			14,663
	General and administrative(1)			13,019			22,722			37,186			16,780			26,463
	Depreciation and amortization			13,414			18,213			28,676			12,778			16,818
	Loss (gain) on disposal of assets			351			391			2,616			1,863			(50	)
		Total expenses		105,644			164,939			280,638			128,021			171,208
Operating income				3,107			15,960			30,864			13,844			32,423
Net interest expense				(4,750	)		(5,174	)		(9,550	)		(4,162	)		(6,002	)
Loss on early extinguishment of debt				—			(5,197	)		—			—			—
Other income (expense)				31			146			(398	)		25			137
Income (loss) from continuing operations before income taxes				(1,612	)		5,735			20,916			9,707			26,558
Income tax (expense) benefit				382			(2,772	)		(7,984	)		(3,705	)		(10,010	)
Income (loss) from continuing operations				(1,230	)		2,963			12,932			6,002			16,548
Discontinued operations, net of tax				—			22			(71	)		88			—
Cumulative effect of accounting change, net of tax				—			(151	)		—			—			—
Net income (loss)				(1,230	)		2,834			12,861			6,090			16,548
Preferred stock dividend				(1,075	)		(1,525	)		—			—			—
Accretion of preferred stock discount				(374	)		(3,424	)		—			—			—
Net income (loss) available to common stockholders			$	(2,679	)	$	(2,115	)	$	12,861		$	6,090		$	16,548
Net income (loss) per common share:
	Basic		$	(0.13	)	$	(0.09	)	$	0.46		$	0.22		$	0.58
	Diluted		$	(0.13	)	$	(0.09	)	$	0.42		$	0.20		$	0.51
Other Financial Data:
EBITDA(2)			$	16,552		$	28,993		$	59,071		$	26,735		$	49,378
Cash flows from operating activities				17,012			29,815			46,539			19,685			44,823
Cash flows from investing activities				(45,303	)		(84,903	)		(73,587	)		(28,803	)		(45,354	)
Cash flows from financing activities				21,572			79,859			21,498			(2,661	)		(5,550	)
Capital expenditures:
	Acquisitions, net of cash acquired			31,075			61,885			19,284			5,434			9,885
	Property and equipment			14,674			23,501			55,674			23,928			35,488

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	As of December 31,						As of June 30, 2005
	2002		2003		2004		Actual		As Adjusted(3)
							(unaudited)
	(dollars in thousands)
Balance Sheet Data:
Cash and cash equivalents	$	926	$	25,697	$	20,147	$	14,066	$	37,266
Net property and equipment		108,487		188,243		233,451		264,758		264,758
Total assets		156,502		302,653		367,601		406,910		430,110
Total long-term debt		39,706		142,116		170,915		166,442		96,442
Mandatorily redeemable preferred stock		12,093		—		—		—		—
Total stockholders' equity (as restated for 2002)		72,558		107,295		121,786		139,953		233,153

(1)

Includes approximately $994,000 and $1,587,000 of non-cash stock-based compensation expense for the years ended December 31, 2003 and 2004 and $631,000 and $1,359,000 for the six months ended June 30, 2004 and 2005, respectively.

(2)

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 (loss), which is the most directly comparable GAAP financial performance measure, and to cash flows from operating activities, which is the most directly comparable GAAP liquidity measure, for each of the periods indicated:

		Year Ended December 31,							Six Months Ended June 30,
		2002 (restated)			2003 (restated)
							2004		2004		2005
									(unaudited)
		(dollars in thousands)
Reconciliation of EBITDA to Net Income (Loss):
Net income (loss)		$	(1,230	)	$	2,834	$	12,861	$	6,090	$	16,548
	Income taxes		(382	)		2,772		7,984		3,705		10,010
	Net interest expense		4,750			5,174		9,550		4,162		6,002
	Depreciation and amortization		13,414			18,213		28,676		12,778		16,818
EBITDA		$	16,552		$	28,993	$	59,071	$	26,735	$	49,378

(3)

Gives effect to this offering and the application of our estimated net proceeds from this offering as set forth under "Use of Proceeds" as if each had occurred on June 30, 2005.

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Operating Data

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

•

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



•

our rig utilization rate is calculated using 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.

	Year Ended December 31,									Six Months Ended June 30,
	2002			2003			2004			2004			2005
Well Servicing
Weighted average number of rigs		225			257			279			274			297
Rig hours (000's)		383.2			523.9			618.8			300.5			367.7
Rig utilization rate		59.7	%		71.4	%		77.8	%		76.7	%		86.6	%
Revenue per rig hour	$	193		$	199		$	230		$	220		$	268
Segment profits per rig hour	$	48		$	59		$	72		$	69		$	101
Segment profits as a percent of revenue		24.7	%		29.6	%		31.2	%		31.3	%		37.7	%
Fluid Services
Weighted average number of fluid service trucks		196			249			386			374			431
Revenue per fluid service truck (000's)	$	174		$	212		$	256		$	124		$	141
Segment profits per fluid service truck (000's)	$	58		$	74		$	87		$	42		$	50
Segment profits as a percent of revenue		33.6	%		34.8	%		34.0	%		33.8	%		35.7	%
Drilling and Completion Services
Segment profits as a percent of revenue		30.2	%		36.8	%		40.4	%		41.8	%		47.6	%
Well Site Construction Services
Segment profits as a percent of revenue		—			28.3	%		23.1	%		22.9	%		26.2	%

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

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RISK FACTORS

You should carefully consider the risks described below, as well as the other information included in this prospectus, before making 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 $60 per barrel and $9.00 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 and $41.51 per barrel in 2003 and 2004, respectively, and the average wellhead price for natural gas, as recorded by the Energy Information Agency, was $4.98 and $5.49 per mcf for 2003 and 2004, 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.

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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 five new personnel and positions, including directors of financial reporting and treasury. 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, 2004, 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.

        Upon completion of this offering, we will 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

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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, which may not be available to us.

        Our business is capital intensive, requiring specialized equipment to provide our services. We may need to raise additional funds through public or private debt or equity financings. Adequate funds may not be available when needed or may not be available on favorable terms. If we raise additional funds by issuing equity securities, dilution to existing stockholders may result. If funding is insufficient at any time in the future, we may be unable to fund maintenance requirements, acquisitions, take advantage of business opportunities or respond to competitive pressures, any of which could harm our business.

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 2004 and the first six months of 2005, our top five customers accounted for 20% and 17%, respectively, of our revenues. The loss of any one of our largest customers or a sustained decrease in demand by any of such customers could result in a substantial loss of revenues and could have a material adverse effect on our results of operations.

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

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

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

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

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

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

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

•

personal injury or loss of life;



•

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



•

suspension of operations.

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

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

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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.

        We now have, and after this offering will continue to have, a significant amount of indebtedness. As of June 30, 2005, our total debt, the majority of which bears interest at variable rates, was $180.5 million, including the aggregate principal amount due under the term loan portion of our senior credit facility of $163.0 million and capital lease obligations in the aggregate amount of $17.5 million. As of June 30, 2005, on an as adjusted basis (as if we had completed this offering and used the net proceeds as described in "Use of Proceeds" on that date), our total debt would have been $110.5 million. For the year ended December 31, 2004, we made cash principal and interest payments totaling $8.8 million. Holding all other variables constant, if interest rates increased by 1%, our annual interest expense (excluding effects of our interest rate hedges) would have increased by approximately $1.7 million during 2004. Our market risks at June 30, 2005 are similar to those disclosed for the year ended December 31, 2004.

        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;

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•

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



•

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



•

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

        If we are unable to generate sufficient cash flow or are otherwise unable to obtain the funds required to make principal and interest payments on our indebtedness, or if we otherwise fail to comply with the various covenants in our senior credit facility or other instruments governing any future indebtedness, we could be in default under the terms of our senior credit facility or such instruments. In the event of a default, the holders of our indebtedness could elect to declare all the funds borrowed under those instruments to be due and payable together with accrued and unpaid interest, the lenders under our credit facilities 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 existing credit facility imposes restrictions on us that may affect our ability to successfully operate our business.

        Our senior credit facility limits our ability to take various actions, such as:

•

limitations on the incurrence of additional indebtedness;



•

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



•

limitation on dividends and distributions.

        In addition, our senior credit facility requires us to maintain certain financial ratios and to satisfy certain financial conditions, several of which become more restrictive over time and may require us to reduce our debt or take some other action in order to comply with them. These restrictions could also limit our ability to obtain future financings, make needed capital expenditures, withstand a downturn in our business or the economy in general, or otherwise conduct necessary corporate activities. We also may be prevented from taking advantage of business opportunities that arise because of the limitations imposed on us by the restrictive covenants under our senior credit facility. Please read "Management's Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Credit Facilities — 2004 Credit Facility" for a discussion of our senior 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

DLJ Merchant Banking effectively controls the outcome of stockholder voting and may exercise this voting power in a manner adverse to our other stockholders.

        After giving effect to this offering, DLJ Merchant Banking effectively will own approximately    % of our outstanding common stock, or    % if the underwriters exercise their over-allotment option in

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full. Accordingly, DLJ Merchant Banking is in a position to effectively control the outcome of matters requiring a stockholder vote, including the election of directors, adoption of amendments to our certificate of incorporation or bylaws or approval of transactions involving a change of control. The interests of DLJ Merchant Banking may differ from those of our other stockholders, and DLJ Merchant Banking may vote its common stock in a manner that may adversely affect our other stockholders. Please read "Security Ownership of Certain Beneficial Owners and Management" for a discussion of DLJ Merchant Banking's ownership interests in us and "Certain Relationships and Related Party Transactions — Transactions with DLJ Merchant Banking" for a description of DLJ Merchant Banking.

Affiliates of Credit Suisse First Boston LLC, one of the underwriters of this offering, are selling stockholders, which may present conflicts of interest.

        The funds that comprise DLJ Merchant Banking are affiliates of Credit Suisse First Boston LLC. Because DLJ Merchant Banking is a selling stockholder in this offering, this relationship may present conflicts of interest for Credit Suisse First Boston LLC. Accordingly, this offering will be made in accordance with the applicable provisions of Rule 2720 of the Conduct Rules of the National Association of Securities Dealers, Inc., which requires, among other things, that the initial public offering price be no higher than that recommended by a "qualified independent underwriter." Goldman, Sachs & Co. is serving as the qualified independent underwriter in connection with this offering. See "Underwriting."

The cessation of operations by Arthur Andersen LLP will limit our ability to use the consolidated financial statements audited by Arthur Andersen LLP and could impact our investors' ability to seek potential recoveries from Arthur Andersen LLP.

        The consolidated financial statements of First Energy Services Company (as predecessor entity to FESCO Holdings, Inc., which we acquired in 2003) and its subsidiaries as of and for the years ended December 31, 2001 and 2000 were audited by Arthur Andersen LLP, independent public accountants, as indicated in their reports with respect thereto, and are included in this prospectus in reliance upon the authority of said firm as experts in giving said reports. Subsequent to Arthur Andersen LLP's completion of the 2001 audit of First Energy Services Company and its subsidiaries, the firm was convicted of obstruction of justice charges relating to a federal investigation of Enron Corporation, has ceased practicing before the SEC and has lost the services of the material personnel responsible for said audit. As a result, it is not possible to obtain Arthur Andersen LLP's consent to the inclusion of their report in this prospectus, and we have dispensed with the requirement to file their consent in reliance upon Rule 437a of the Securities Act of 1933. Because Arthur Andersen LLP has not consented to the inclusion of their report in this prospectus, you will not be able to recover against Arthur Andersen LLP under Section 11 of the Securities Act for any untrue statements of a material fact contained in the consolidated financial statements audited by Arthur Andersen LLP or any omissions to state a material fact required to be stated therein.

Risks Related to this Offering

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.

        After this offering, we will have outstanding             shares of common stock. Of these shares, the             shares we and the selling stockholders are selling in this offering, or             shares if the underwriters exercise their over-allotment option in full, 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. A total of             shares, or             shares if the underwriters exercise their over-allotment option in full, will be "restricted securities" (within the meaning of

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Rule 144 under the Securities Act) or subject to lock-up arrangements. In connection with this offering, we, our officers and directors and substantially all of our existing stockholders (including the selling stockholders) have entered into lock-up agreements under which we and they have agreed not to offer or sell any shares of common stock or securities convertible into or exchangeable or exercisable for shares of common stock for an initial period of 180 days from the date of this prospectus, which may be extended for up to 34 days in certain circumstances, without the prior written consent of Goldman, Sachs & Co. and Credit Suisse First Boston LLC on behalf of the underwriters. Goldman, Sachs & Co. and Credit Suisse First Boston LLC may, at any time and without notice, waive any of the terms of these lock-up agreements. See "Underwriting" for a description of these lock-up agreements. An aggregate of    of these shares will become available for resale in the public market as shown in the chart below.

Number of shares	Date of eligibility for resale into public market
	No less than 180 days after the date of this prospectus (in accordance with lock-up agreements with Goldman, Sachs & Co. and Credit Suisse First Boston LLC)
	Between 181 and 365 days after the date of this prospectus due to the requirements of the federal securities laws.

        After this offering, the holders of             shares of our common stock 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 soon as practicable after this offering, we intend to file one or more registration statements 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 certain of our stockholders have entered into, shares registered under these registration statements on Form S-8 will be available for resale immediately in the public market without restriction.

Purchasers of common stock will experience immediate and substantial dilution.

        Based on an assumed initial public offering price of $    per share, purchasers of our common stock in this offering will experience an immediate and substantial dilution of $    per share in the net tangible book value per share of common stock from the initial public offering price, and our pro forma net tangible book value as of June 30, 2005 after giving effect to this offering would be $    per share. Please read "Dilution" for a complete description of the calculation of net tangible book value.

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

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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 existing senior credit facility restrict the payment of dividends without the prior written consent of the lenders. Investors must rely on sales of their common stock after price appreciation, which may never occur, as the only way to realize a return on their investment. Investors seeking cash dividends should not purchase our common stock.

There has been no active trading market for our common stock, and an active trading market may not develop.

        Prior to this offering, there has been no public market for our common stock. We have applied to list our common stock on the New York Stock Exchange. We do not know if an active trading market will develop for our common stock or how the common stock will trade in the future, which may make it more difficult for you to sell your shares. Negotiations between the underwriters, the selling stockholders and us will determine the initial public offering price. You may not be able to resell your shares at or above the initial public offering price.

If our stock price declines after the initial offering, 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;

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•

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.

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FORWARD-LOOKING STATEMENTS AND INDUSTRY DATA

        This prospectus contains forward-looking statements. 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.

-20-

THE COMPANY

        We commenced business in 1992 through our predecessor company. In December 2000, we completed a private recapitalization by DLJ Merchant Banking, which gained majority control of us. DLJ Merchant Banking has contributed approximately $81 million through several equity investments and has been instrumental in providing and arranging capital to drive our growth. Since our formation, we have grown largely through acquisitions of businesses and assets, including 35 acquisitions from January 2001 through June 30, 2005. Primarily through these transactions, our revenues have grown from $56.5 million in 2000 to $311.5 million in 2004 and $203.6 million for the six months ended June 30, 2005.

        In January 2003, we completed a holding company reorganization to provide greater operational, administrative and financial flexibility. All of the then-outstanding shares of common stock and preferred stock of our predecessor were exchanged for shares of a new holding company then known as BES Holding Co. in a tax-free exchange. The shares of then-outstanding common stock and preferred stock were exchanged on a one-for-one basis, 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. Our predecessor was converted into a limited partnership now known as Basic Energy Services, L.P., which currently remains our indirect, wholly owned subsidiary. In April 2004, we changed our name from BES Holding Co. to Basic Energy Services, Inc.

-21-

USE OF PROCEEDS

        We expect to receive net proceeds from this offering of approximately $93.2 million, assuming an initial public offering price of $    per share and after deducting underwriting discounts and commissions and estimated offering expenses. We will not receive any of the net proceeds from the sale of shares of common stock by the selling stockholders. One of the selling stockholders owns a majority of the shares of our outstanding common stock and is also an affiliate of Credit Suisse First Boston, one of the underwriters of this offering. See "Risk Factors — Risks Related to Our Relationship with DLJ Merchant Banking," "Selling Stockholders" and "Underwriting."

        We plan to use $70.0 million of our net proceeds from this offering to repay a portion of the term loan under our credit facility. We will use an estimated $     million of the proceeds (assuming an initial public offering price of $         per share) to repurchase an aggregate of up to 167,583 shares of our common stock at the initial public offering price, less underwriting discounts and commissions, from ten officers on the closing date of this offering. We will use the remaining $                million for working capital and general corporate purposes, which may include cash payments made in connection with future acquisitions. We do not currently have any pending agreements or letters of intent for any significant acquisitions.

        Our current senior credit facility consists of a $50 million revolving credit facility and a term loan facility of $170 million. As of June 30, 2005, we had $163.2 million of indebtedness outstanding under the term loan portion of our senior credit facility, including approximately $196,000 of accrued interest. The term loan bears interest at either a base rate plus 2.0%, or the London Interbank Offered Rate ("LIBOR") plus 3.0%, and becomes due and payable in October 2009. As of June 30, 2005, we had no indebtedness outstanding under our revolving credit facility, other than $8.3 million of stand-by letters of credit. Our borrowings under the term loan and revolving credit facility were used to refinance existing debt and to provide for ongoing working capital and general corporate purposes, including acquisitions of new well servicing rigs, acquisitions of businesses (including our October 2005 acquisition of Oilwell Fracturing Services, Inc.) and capital leases issued for equipment.

        The shares are being repurchased subject to our lenders' consent from the ten officers 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 being repurchased represent up to 39.2% of the vested shares of each officer issued as compensation to them. We will withhold minimum tax liability requirements from these proceeds and pay the remainder of the proceeds to the officers for their use in paying estimated tax liabilities. The executive officers and maximum number of shares that we will repurchase upon the closing of this offering are as follows: Kenneth V. Huseman—101,975 shares; James J. Carter—27,327 shares; Dub W. Harrison—10,688 shares; and Charles W. Swift—10,688 shares. For further discussion on our agreements regarding the repurchase of these shares, please see "Certain Relationships and Related Party Transactions" and "Principal Stockholders."

        Please read "Management's Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Credit Facilities — 2004 Credit Facility" for a description of our outstanding indebtedness and our senior credit facility following this offering.

DIVIDEND POLICY

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

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CAPITALIZATION

        The following table sets forth our capitalization at June 30, 2005:

•

on an actual basis; and



•

on an as adjusted basis to give effect to this offering and the application of our estimated net proceeds from this offering as set forth under "Use of Proceeds," including the repurchase of up to 167,583 shares of our common stock concurrently with the closing of this offering, as if each had occurred on June 30, 2005.

        The share information on an actual and as adjusted basis also gives effect to a 5-for-1 stock split effected as a stock dividend on September 26, 2005. 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 these consolidated financial statements, "Management's Discussion and Analysis of Financial Condition and Results of Operations" and "Use of Proceeds."

				June 30, 2005
				Actual			As Adjusted
				(in thousands)
Cash and cash equivalents				$	14,066		$	37,266
Total long-term debt, including current portion:
	Notes payable:
		Term loan under senior credit facility		$	163,000		$	93,000
		Other debt and obligations under capital leases			17,514			17,514
			Total		180,514			110,514
Stockholders' equity:
	Common stock, $.01 par value, 80,000,000 shares authorized; 28,931,935 shares issued and 28,920,685 shares outstanding;              shares issued and              shares outstanding, as adjusted				58
	Additional paid-in capital				148,228
	Deferred compensation				(9,057	)		(9,057	)
	Retained earnings (deficit)				421			421
	Treasury stock, 11,250 shares at June 30, 2005, at cost				—			—
	Accumulated other comprehensive income				303			303
			Total stockholders' equity		139,953
			Total capitalization	$	320,467		$

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DILUTION

        Purchasers of the common stock in this offering will experience immediate and substantial dilution in the net tangible book value per share of the common stock for accounting purposes. Net tangible book value per share represents the amount of the total tangible assets less our total liabilities, divided by the number of shares of common stock that will be outstanding after giving effect to a 5-for-1 stock split effected as a stock dividend on September 26, 2005. At June 30, 2005, we had a net tangible book value of $92.1 million, or $3.18 per share of outstanding common stock after giving effect to the 5-for-1 stock split. After giving effect to the sale of             shares of common stock in this offering at an assumed initial public offering price of $             per share and after the deduction of underwriting discounts and commissions and estimated offering expenses, the as adjusted net tangible book value at June 30, 2005 would have been $             million or $                    per share. This represents an immediate increase in such net tangible book value of $                    per share to existing stockholders and an immediate and substantial dilution of $                    per share to new investors purchasing common stock in this offering. The following table illustrates this per share dilution:

Assumed initial public offering price per share				$
	Net tangible book value per share as of June 30, 2005	$	3.18
	Increase attributable to new public investors	$
As adjusted net tangible book value per share after this offering				$
Dilution in as adjusted net tangible book value per share to new investors				$

        The following table summarizes, on an as adjusted basis set forth above as of June 30, 2005, the total number of shares of common stock owned by existing stockholders (net of shares being repurchased by us concurrently with the closing of this offering) and to be owned by new investors, the total consideration paid, and the average price per share paid by our existing stockholders and to be paid by new investors in this offering at $                    , the mid-point of the range of the initial public offering prices set forth on the cover page of this prospectus, calculated before deduction of estimated underwriting discounts and commissions.

		Shares Purchased(1)			Total Consideration
									Average Price Per Share
		Number	Percent		Amount		Percent
Existing Stockholders(2)		28,920,685		%	$	126,544,313	55.9	%	$	4.37
New Public Investors						100,000,000	44.1	%
	Total		100.0	%	$	226,544,313	100.0	%

(1)

The number of shares disclosed for the existing stockholders includes             shares being sold by the selling stockholders in this offering. The number of shares disclosed for the new investors does not include the             shares being purchased by the new investors from the selling stockholders in this offering.

(2)

With respect to our executive officers, directors and greater-than-10% stockholders, and assuming the exercise of all outstanding warrants and stock options, the number of shares of common stock purchased from us (excluding shares being repurchased by us concurrently

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with the closing of this offering), the total consideration paid to us, and the average price per share paid by all of those affiliated persons, are as follows:

	Shares Purchased			Total Consideration
								Average Price Per Share
	Number	Percent		Amount		Percent
Affiliated persons	34,395,930		%	$	148,349,848		%	$	4.31

        As of June 30, 2005, there were 28,920,685 shares of our common stock outstanding, after giving effect to the 5-for-1 stock split, held by 36 stockholders of record. Repurchases of shares by us as described in "Use of Proceeds" and sales by the selling stockholders in this offering will reduce the number of shares of common stock held by existing stockholders to             or approximately             % of the total number of shares of common stock outstanding after this offering and will increase the number of shares of common stock held by new investors to                      or approximately             % of the total number of shares of common stock outstanding after this offering.

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SELECTED HISTORICAL FINANCIAL DATA

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

			Year Ended December 31,															Six Months Ended June 30,
			2000			2001			2002			2003			2004			2004			2005
						(restated)			(restated)			(restated)						(unaudited)
			(dollars in thousands, except per share data)
Statement of Operations Data:
Revenues:
	Well servicing		$	37,784		$	62,943		$	73,848		$	104,097		$	142,551		$	66,098		$	98,650
	Fluid services			18,682			36,766			34,170			52,810			98,683			45,006			60,839
	Drilling and completion services			—			—			733			14,808			29,341			12,116			24,276
	Well site construction services			—			—			—			9,184			40,927			18,645			19,866
		Total revenues		56,466			99,709			108,751			180,899			311,502			141,865			203,631
Expenses:
	Well servicing			27,475			40,906			55,643			73,244			98,058			45,416			61,464
	Fluid services			12,639			21,363			22,705			34,420			65,167			29,743			39,119
	Drilling and completion services			—			—			512			9,363			17,481			7,057			12,731
	Well site construction services			—			—			—			6,586			31,454			14,384			14,663
	General and administrative(1)			6,683			10,813			13,019			22,722			37,186			16,780			26,463
	Depreciation and amortization			6,795			9,599			13,414			18,213			28,676			12,778			16,818
	Loss (gain) on disposal of assets			(91	)		(10	)		351			391			2,616			1,863			(50	)
	Unsuccessful offering and acquisition costs			2,073			—			—			—			—
		Total expenses		55,574			82,671			105,644			164,939			280,638			128,021			171,208
Operating income				892			17,038			3,107			15,960			30,864			13,844			32,423
Net interest expense				(6,837	)		(3,303	)		(4,750	)		(5,174	)		(9,550	)		(4,162	)		(6,002	)
Gain (loss) on early extinguishment of debt				17,681			(1,462	)		—			(5,197	)		—			—			—
Other income (expense)				76			16			31			146			(398	)		25			137
Income (loss) from continuing operations before income taxes				11,812			12,289			(1,612	)		5,735			20,916			9,707			26,558
Income tax (expense) benefit				2,320			(4,688	)		382			(2,772	)		(7,984	)		(3,705	)		(10,010	)
Income (loss) from continuing operations				14,132			7,601			(1,230	)		(2,963	)		12,932			6,002			16,548
Discontinued operations, net of tax				—			—			—			22			(71	)		88			—
Cumulative effect of accounting change, net of tax				—			—			—			(151	)		—			—			—
Net income (loss)				14,132			7,601			(1,230	)		2,834			12,861			6,090			16,548
Preferred stock dividend				(645	)		—			(1,075	)		(1,525	)		—			—			—
Accretion of preferred stock discount				—			—			(374	)		(3,424	)		—			—			—
Net income (loss) available to common stockholders			$	13,487		$	7,601		$	(2,679	)	$	(2,115	)	$	12,861		$	6,090		$	16,548
Basic earnings (loss) per share of common stock:
	Continuing operations less preferred stock dividend and accretion		$	5.46		$	0.49		$	(0.13	)	$	(0.09	)	$	0.46		$	0.21		$	0.58
	Discontinued operations			—			—			—			—			—			0.01			—
	Cumulative effect of accounting change			—			—			—			—			—			—			—
Net income (loss) available to common stockholders			$	5.46		$	0.49		$	(0.13	)	$	(0.09	)	$	0.46		$	0.22		$	0.58
Diluted earnings (loss) per share of common stock:
	Continuing operations less preferred stock dividend and accretion		$	5.46		$	0.49		$	(0.13	)	$	(0.09	)	$	0.42		$	0.19		$	0.51
	Discontinued operations			—			—			—			—			—			0.01			—
	Cumulative effect of accounting change			—			—			—			—			—			—			—
Net income (loss) available to common stockholders			$	5.46		$	0.49		$	(0.13	)	$	(0.09	)	$	0.42		$	0.20		$	0.51
Other Financial Data:
EBITDA(2)			$	25,444		$	25,191		$	16,552		$	28,993		$	59,071		$	26,735		$	49,378
Cash flows from operating activities				7,318			14,060			17,012			29,815			46,539			19,685			44,823
Cash flows from investing activities				(3,782	)		(60,305	)		(45,303	)		(84,903	)		(73,587	)		(28,803	)		(45,354	)
Cash flows from financing activities				(1,480	)		(50,770	)		21,572			79,859			21,498			(2,661	)		(5,550	)
Capital expenditures:
	Acquisitions, net of cash acquired			80			44,928			31,075			61,885			19,284			5,434			9,885
	Property and equipment			4,255			15,208			14,674			23,501			55,674			23,928			35,488

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	As of December 31,
											As of June 30, 2005
	2000		2001		2002		2003		2004
											(unaudited)
	(dollars in thousands)
Balance Sheet Data:
Cash and cash equivalents	$	3,118	$	7,645	$	926	$	25,697	$	20,147	$	14,066
Property and equipment, net		32,780		78,602		108,487		188,243		233,451		264,758
Total assets		53,018		126,207		156,502		302,653		367,601		406,910
Long-term debt		15,390		45,258		39,706		142,116		170,915		166,442
Mandatorily redeemable cumulative preferred stock		—		—		12,093		—		—		—
Stockholders' equity (deficit) (as restated for 2001 and 2002)		21,537		58,938		72,558		107,295		121,786		139,953

(1)

Includes approximately $994,000 and $1,587,000 of non-cash stock compensation expense for the years ended December 31, 2003 and 2004 and $631,000 and $1,359,000 for the six months 2004 and 2005, respectively.

(2)

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 the non-GAAP financial measures of EBITDA to the most directly comparable GAAP financial measures on a historical basis for each of the periods indicated.

		Year Ended December 31,												Six Months Ended June 30,
		2000			2001		2002			2003		2004		2004		2005
					(restated)		(restated)			(restated)				(unaudited)
		(dollars in thousands)
Reconciliation of EBITDA to Net Income (Loss):
Net income (loss)		$	14,132		$	7,601	$	(1,230	)	$	2,834	$	12,861	$	6,090	$	16,548
	Income tax (expense) benefit		(2,320	)		4,688		(382	)		2,772		7,984		3,705		10,010
	Net interest expense		6,837			3,303		4,750			5,174		9,550		4,162		6,002
	Depreciation and amortization		6,795			9,599		13,414			18,213		28,676		12,778		16,818
EBITDA		$	25,444		$	25,191	$	16,552		$	28,993	$	59,071	$	26,735	$	49,378

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MANAGEMENT'S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Management's Overview

        We provide a wide range of well site services to oil and gas drilling and producing companies, including well servicing, fluid services, drilling and completion services and well site construction services. Our results of operations since the beginning of 2002 reflect the impact of our acquisition strategy as a leading consolidator in the domestic land-based well services industry during this period. Our acquisitions have increased our breadth of service offerings at the well site and expanded our market presence. In implementing this strategy, we have purchased businesses and assets in 35 separate acquisitions from January 1, 2001 to June 30, 2005. Our weighted average number of well servicing rigs has increased from 126 in 2001 to 303 in the second quarter of 2005, and our weighted average number of fluid service trucks has increased from 156 to 447 in the same period. In 2003, primarily through acquisitions, we significantly increased our drilling and completion (principally pressure pumping) services and entered the well site construction services segment. These acquisitions make changes in revenues, expenses and income not directly comparable.

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

		Year Ended December 31,												Six Months Ended June 30,
		2002				2003				2004				2004				2005
Revenues:
Well servicing		$	73.8	68	%	$	104.1	58	%	$	142.6	46	%	$	66.1	46	%	$	98.6	48	%
Fluid services			34.2	31	%		52.8	29	%		98.7	32	%		45.0	32	%		60.8	30	%
Drilling and completion services			0.7	1	%		14.8	8	%		29.3	9	%		12.1	9	%		24.3	12	%
Well site construction services			—	0	%		9.2	5	%		40.9	13	%		18.6	13	%		19.9	10	%
	Total revenues	$	108.7	100	%	$	180.9	100	%	$	311.5	100	%	$	141.9	100	%	$	203.6	100	%

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

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

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

•

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



•

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



•

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



•

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

Segment profits are computed as segment operating revenue 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 expect our business strategy will continue to include growth through selective acquisitions. Our continued rate of growth will depend on our ability to identify attractive acquisition opportunities and to acquire identified targets at commercially reasonable prices. We will also continue integrating current or future acquisitions into our existing operations. 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 2002 through 2004, we grew significantly through acquisitions and capital expenditures. During 2002 and 2003, this growth was focused more on acquisitions of new lines of related business and of regional platforms for our existing businesses. During 2004, we directed our focus more at the integration and expansion of these businesses, including capital expenditures of selected assets to expand our existing businesses.

        We discuss the aggregate purchase prices and related financing issues below in "— Liquidity and Capital Resources" and present the historical financial statements of certain significant acquisitions in the historical financial statements included with 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 $916,000 had been earned as of December 31, 2004.

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

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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 earnout payments, of which none had been earned as of December 31, 2004.

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.

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Segment Overview

Well Servicing

        During the first six months of 2005, our well servicing segment represented 48% of our revenue. 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, 2002, 2003 and 2004, and the quarters ended March 31 and June 30, 2005:

	Weighted Average Number of Rigs	Rig Hours	Rig Utilization Rate		Revenue Per Rig Hour		Segment Profits Per Rig Hour		Segment Profits %
2002:
First Quarter	193	77,400	56.1	%	$	201	$	47	23.7	%
Second Quarter	203	88,800	61.2	%	$	197	$	56	28.4	%
Third Quarter	250	106,700	59.7	%	$	188	$	49	26.1	%
Fourth Quarter	252	110,300	61.2	%	$	188	$	40	21.4	%
Full Year	225	383,200	59.7	%	$	193	$	48	24.7	%
2003:
First Quarter	252	128,200	71.2	%	$	188	$	52	27.8	%
Second Quarter	252	131,000	72.7	%	$	195	$	62	31.9	%
Third Quarter	252	133,200	73.9	%	$	200	$	62	30.9	%
Fourth Quarter	270	131,500	68.1	%	$	211	$	59	27.8	%
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	%

        Our utilization declined to a low of 56% in the first quarter of 2002. This decline in utilization during 2002 contributed to our net loss for this period. Since this low point, our utilization has improved to 89% in the second quarter of 2005.

        In 2002, well servicing rates declined marginally due to the lower activity levels. In addition, our rates were adversely affected by the mix of acquisitions that were made in 2002, as a majority of our rig acquisitions in mid-2002 were in areas with lower market rates than our average rate. This

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affected our average rates during the third quarter of 2002. However, since the beginning of 2003, we have been able to increase our rates, which has contributed to our improved segment profits.

        During the first six months of 2005, both rig utilization and revenue per rig hour continued to improve as a result of higher demand for our equipment and services.

Fluid Services

        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, 2002, 2003 and 2004, and the quarters ended March 31 and June 30, 2005 (dollars in thousands):

	Weighted Average Number of Fluid Service Trucks	Revenue Per Fluid Service Truck		Segment Profits Per Fluid Service Truck		Segment Profits %
2002:
First Quarter	183	$	44	$	16	36.1	%
Second Quarter	183	$	43	$	12	28.2	%
Third Quarter	208	$	45	$	17	37.0	%
Fourth Quarter	209	$	43	$	14	32.5	%
Full Year	196	$	174	$	58	33.6	%
2003:
First Quarter	202	$	51	$	16	31.5	%
Second Quarter	209	$	53	$	18	35.0	%
Third Quarter	223	$	50	$	18	35.4	%
Fourth Quarter	363	$	56	$	21	36.1	%
Full Year	249	$	212	$	74	34.8	%
2004:
First Quarter	371	$	60	$	21	34.4	%
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	414	$	71	$	24	34.4	%
Second Quarter	447	$	71	$	26	37.0	%

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        We gauge activity levels in our fluid services segment based on revenues and segment profits per fluid service truck. Reduced capital spending by oil and gas companies during 2002 affected our fluid services segment more significantly than our well servicing segment. In 2002, our revenues per fluid services truck and segment profits as a percent of revenue were approximately $174,000 and 33.6%, respectively, compared to $239,000 and 41.9%, respectively, during 2001. This decline in profitability resulted from a decline in drilling-related revenues and lower overall levels of business activity in base fluid services. Increased oilfield activity since the third quarter of 2002 has led to a recovery in our fluid services segment, including the implementation of price increases.

        In 2003, our revenues per truck increased by approximately $38,000, or 22%, over 2002 to approximately $212,000, and our segment profits per truck increased by approximately $16,000, or 28%. These increases were due to improved market conditions, additional frac tanks, and improved pricing.

        In 2004, our revenues per truck increased by approximately $44,000, or 21%, over 2003 to approximately $256,000 and our segment profits per truck increased by approximately $13,000, or 18%. The revenue increase was due to a combination of higher utilization, a positive change in our service mix, and minor improvements in pricing. Our segment profits improved due to the factors mentioned above, plus the continued addition of frac tanks.

        During the first six months of 2005, our revenue per fluid services truck totaled approximately $141,000 as compared to approximately $124,000 in the same period in 2004. This increase was due to improved market conditions and pricing.

Drilling and Completion Services

        During the first six months of 2005, our drilling and completion services segment represented 12% of our revenue. Revenue 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 and underbalanced drilling.

        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 New Force and Ark-La-Tex 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."

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

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        We gauge the performance of our drilling and completion services segment based on the segment's operating revenue and segment profits. Lower segment profits could be the result of lower rates being charged, lower utilization of related equipment, or a combination of both.

        The following is an analysis of our drilling and completion services for the quarter ended December 31, 2002 (when we first entered this segment), each of the quarters and years in the years ended December 31, 2003 and 2004, and the quarters ended March 31 and June 30, 2005 (dollars in thousands):

	Revenue		Segment Profits %
2002:
Fourth Quarter	$	733	30.2	%
2003:
First Quarter	$	2,642	45.6	%
Second Quarter	$	3,454	31.5	%
Third Quarter	$	4,180	37.9	%
Fourth Quarter	$	4,532	32.3	%
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	38.1	%
Full Year	$	29,341	40.4	%
2005:
First Quarter	$	10,765	45.6	%
Second Quarter	$	13,512	49.1	%

Well Site Construction Services

        During the first six months of 2005, our well site construction services segment represented 10% of our revenue. Revenue from our well site construction services segment is 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. These services are independent of our other services and, while offered to some customers utilizing other services, are not offered on a bundled basis. 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.

        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.

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

	Revenue		Segment Profits %
2003:
Fourth Quarter	$	9,184	28.3	%
2004:
First Quarter	$	8,776	24.6	%
Second Quarter	$	9,868	21.3	%
Third Quarter	$	11,298	24.3	%
Fourth Quarter	$	10,985	22.4	%
Full Year	$	40,927	23.1	%
2005:
First Quarter	$	8,952	20.6	%
Second Quarter	$	10,914	30.8	%

        In the fourth quarter of 2003, this segment had revenues of $9.2 million with segment profits of $2.6 million, or 28.3%, while in 2004, this segment had revenues of $40.9 million with segment profits of $9.5 million and 23.1%. The decrease in revenues from the third quarter to the fourth quarter is primarily due to the seasonality of demand for these assets in our Rocky Mountain division in the winter months.

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 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.

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

        Impairments.    We review our assets for impairment at a minimum annually, or whenever, in management's judgment, events or changes in circumstances indicate that the carrying amount of a long-lived asset may not be recovered over its remaining service life. Provisions for asset impairment are charged to income when the sum of the estimated future cash flows, on an undiscounted basis, is less than the assets' carrying amount. When an 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 $100,000, 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 revenue when the services are performed, collection of the relevant receivables is probable, persuasive evidence of the arrangement exists and the price is fixed and determinable.

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

Critical Accounting Estimates

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

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

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

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

        Litigation and Self-Insured Risk Reserves.    We estimate our reserves related to litigation and self-insure risk based on the facts and circumstances specific to the litigation and self-insured risk claims and our past experience with similar claims. The actual outcome of 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 company, is required to assess goodwill and certain intangible assets for impairment.

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

        Stock-Based Compensation.    We account for stock-based compensation using the intrinsic value method presented by Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees." However, in accordance with SFAS No. 148, "Accounting for Stock-Based Compensation," an amendment to SFAS No. 123, we must estimate the fair value of our outstanding stock-based compensation awards for disclosure purposes. In so doing, we use an option-pricing model (Black-Scholes), which requires various assumptions as to interest rates, volatility, dividend yields and expected lives of stock-based awards.

        The fair value of common stock for options granted from July 1, 2004 through June 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

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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 2 to our June 30, 2005 financial statements, we granted stock options as follows for the twelve-month period ended June 30, 2005.

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

        The reasons for the differences between the fair value per share at the option grant date and the assumed IPO price of $             are as follows:

•

During the three months ended March 31, 2005, we closed five 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 will be 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 will be 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 shown significant increases from January 1, 2005 due to increases in demand caused by increasing commodity prices.

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

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

        Asset Retirement Obligations.    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 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

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retirement obligation, the obligation is adjusted at the end of each quarter to reflect the passage of time, changes in the estimated future cash flows underlying the obligation, acquisition or construction of assets, and settlement of obligations.

Results of Operations

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

Six Months Ended June 30, 2005 Compared to Six Months Ended June 30, 2004

        Revenues.    Revenues increased 44% to $203.6 million in the first six months of 2005 from $141.9 million during the same period in 2004. This increase was due primarily to acquisitions that we made during the last three quarters of 2004 and the first six months of 2005, increased oilfield service activity resulting from continued strong oil and gas prices, and higher utilization rates derived in part from the redeployment of our equipment to take advantage of increasing activity in some of our markets.

        Well servicing revenues increased 49% to $98.6 million in the first six months of 2005 compared to $66.1 million in the first six months of 2004. The increase was due primarily to higher rig utilization, which was due to the general increase in well maintenance activity caused by continued higher oil and gas prices and more aggressive marketing of our fleet in areas of increasing activity. The increased revenue per rig hour reflects minor price increases implemented by us after the first six months of 2004 combined with an improving mix of well servicing activity.

        Fluid services revenues increased 35% to $60.8 million during the first six months of 2005 as compared to $45.0 million during the same period of 2004. The increase in revenue was due primarily to increased activities and our internal growth of, and increase in trucks used by, this segment. We monitor fluid services revenues by the average revenue per fluid service truck. During the first six months of 2005, our average revenue per fluid service truck totaled approximately $141,000 as compared to average revenue of approximately $124,000 per truck during the same period in 2004. Our weighted average number of fluid service trucks also increased approximately 15% from 374 to 431.

        Drilling and completion services revenue increased 100% to $24.3 million during the first six months of 2005 as compared to $12.1 million during the same period of 2004. The increase in revenue between these periods was primarily the result of acquisitions, including our acquisition of wireline and underbalanced drilling businesses during 2004, and internal growth.

        Well site construction services revenue increased 7% to $19.9 million during the first six months of 2005 as compared to $18.6 million during the same period of 2004.

        Direct Operating Expenses.    Direct operating expenses, which primarily consist of labor, including workers compensation and health insurance, and maintenance and repair costs, increased 32% to $128.0 million in the first six months of 2005 from $96.6 million during the same period of 2004 as a result of additional rigs and trucks, as well as higher utilization of our equipment. Direct operating expenses decreased to 63% of revenue for the period from 68% in the same period during 2004, as fixed operating costs such as field supervision, insurance and vehicle expenses were spread over a higher revenue base. We also benefited from a favorable mix of businesses that we acquired and from higher utilization and increased pricing of our services.

        Direct operating expenses for the well servicing segment increased 35% to $61.5 million in the first six months of 2005 as compared to $45.4 million in the same period during 2004 due primarily to increased activity. Segment profits increased to 38% of revenues in the first six months of 2005

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compared to 31% during the same period in 2004, as higher activity levels contributed to lower unit costs per rig hour.

        Direct operating expenses for the fluid services segment increased 32% to $39.1 million in the first six months of 2005 as compared to $29.7 million in the same period during 2004 due primarily to increased activity. Segment profits increased to 36% of revenues in the first six months of 2005 compared to 34% during the same period in 2004.

        Direct operating expenses for the drilling and completion services segment increased 80% to $12.7 million in the first six months of 2005 as compared to $7.1 million for the same period during 2004 due primarily to acquisitions. Our segment profits increased to 48% in the first six months of 2005 from 42% in the same period during 2004.

        Direct operating expenses for the well-site construction services segment increased 2% to $14.7 million in the first six months of 2005 as compared to $14.4 million in the same period during 2004. Segment profits for this segment increased to 26% during the first six months of 2005 as compared to 23% for the same period in 2004.

        General and Administrative Expenses.    General and administrative expenses increased 58% to $26.5 million in the first six months of 2005 from $16.8 million in the first six months of 2004. 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 $16.8 million for the first six months of 2005 and $12.8 million for the first six months of 2004, reflecting the increase in the size and investment in our asset base.

        Interest Expense.    Interest expense increased 46% to $6.2 million in the first six months of 2005 from $4.2 million in the same period during 2004. The increase was due to an approximately $29 million increase in long-term debt, which was used primarily in connection with our acquisitions and expenditures for property and equipment.

        Income Tax Expense (Benefit).    Income tax expense was $10.0 million in the first six months of 2005 as compared to $3.7 million in the first six months of 2004. Our effective tax rate in both periods was approximately 38%.

        Discontinued Operations.    We acquired, as part of the FESCO acquisition in October 2003, certain well servicing assets in Alaska that we made the decision to sell. Accordingly, these assets and related liabilities were held for sale and reflected in our first six months of 2004 financial results for the assets as discontinued operations, but the assets were sold in the third quarter of 2004 at their carrying value and the remaining liability for a property lease charged to discontinued operations.

        Net Income (Loss).    Our net income increased to $16.5 million in the first six months of 2005 from $6.1 million in the same period during 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.

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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 revenue 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.

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        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 as restated, 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 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 approximately $100 million 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 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 (Benefit).    Income taxes increased to an $8.0 million expense in 2004 from a $2.8 million expense in 2003 as restated. 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.

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

Year Ended December 31, 2003 Compared to Year Ended December 31, 2002

        Revenues.    Revenues increased 66% to $180.9 million in 2003 from $108.8 million in 2002. This increase was primarily due to major acquisitions that we made in the first and fourth quarters of 2003, increased oilfield service activity resulting from continued strong oil and gas prices, 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 257 rigs in 2003 compared to 225 in 2002, and 249 fluid service trucks in 2003 compared to 196 in 2002, which also contributed to the increase.

        Well servicing revenues increased 41% to $104.1 million in 2003 compared to $73.8 million in 2002. Our full-fleet utilization rate was 71.4% and revenue per rig hour was $199 in 2003 compared to 59.7% and $193, respectively, for 2002. The higher rig utilization was due to the general increase in oil well maintenance activity caused by continued higher oil and gas prices and more aggressive marketing of our fleet in areas of increasing activity. The increasing rate per hour reflects minor price increases implemented by us combined with a changing mix of activity.

        Fluid services revenues increased 54% to $52.8 million in 2003 from $34.2 million in 2002. We monitor fluid services revenues by our average revenues per truck. During 2003, our average revenues per fluid service truck totaled $212,000, versus average revenues of $174,000 per truck during the same period in 2002.

        Drilling and completion service revenues were $14.8 million during 2003 as compared to $0.7 million during 2002. 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 acquisitions.

        Well site construction service revenues were $9.2 million in 2003 as we entered this segment in the fourth quarter of 2003 with our acquisition of FESCO and PWI.

        Direct Operating Expenses.    Direct operating expenses, which primarily consist of labor, maintenance and fuel, increased 57% to $123.6 million in 2003 from $78.9 million in 2002 as a result of operating additional rigs and trucks, as well as higher utilization of our equipment. Direct operating expenses decreased to 68.4% of revenue for 2003 from 72.5% in 2002, as fixed operating costs such as field supervision, insurance and vehicle expenses were spread over a higher revenue base. We also benefited from a favorable mix of businesses that we acquired, as the majority of the assets acquired in 2003 were fluid services and well site construction services assets. The fluid services line typically produces higher segment profits than the well servicing segment.

        Direct operating expenses for the well servicing segment increased 32% to $73.2 million in 2003 as compared to $55.6 million in 2002 due to increased activity. Segment profits increased to 29.6% of revenues in 2003 compared to 24.7% during 2002, as higher activity levels contributed to lower unit costs per rig hour.

        Direct operating expenses for the fluid services segment increased 52% to $34.4 million in 2003 from $22.7 million in 2002. Segment profits for the fluid services segment increased to 34.8% in 2003 from 33.6% in 2002. This was the result of more drilling-related activity, which generally is higher margin activity, as well as overall higher utilization of our equipment, offset partially by higher fuel costs and rental costs.

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        Direct operating expenses for the drilling and completion services segment were $9.4 million in 2003 as compared to $0.5 million in 2002, and the segment profits for this segment were 36.8% for 2003. Our significant entry into this segment occurred in late January 2003 with the acquisition of New Force, and other equipment additions and acquisitions occurring throughout the remainder of 2003.

        Direct operating expenses for our well site construction services segment in 2003 were $6.6 million, and the segment profits for this segment were 28.3% for this period. We entered this segment in October 2003, as previously discussed.

        General and Administrative Expenses.    General and administrative expenses increased 74.5% to $22.7 million in 2003 as restated from $13.0 million in 2002 as restated, which included $1.0 million of stock-based compensation expense in 2003. 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 management and administrative personnel to support and manage new service locations.

        Depreciation and Amortization Expenses.    Depreciation and amortization expenses were $18.2 million for 2003 and $13.4 for 2002, reflecting the increase in the size and investment in our asset base. We invested $80.7 million for acquisitions in 2003 and an additional $23.5 million for capital expenditures in 2003 (excluding capital leases).

        Interest Expense.    Interest expense increased 8.3% to $5.2 million in 2003 from $4.8 million in 2002. The increase was due to approximately $100 million 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. 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. See "— Liquidity and Capital Resources."

        Income Tax Expense (Benefit).    Income taxes changed to a $2.8 million expense in 2003 as restated from a $382,000 benefit in 2002 as restated. The change was due to improved profitability in 2003. The effective tax rate in 2003 was approximately 48.3% as compared to 23.7% in 2002. The increase in the effective tax rate was due primarily to an adjustment of the tax rate in 2003 to a 35% tax rate and 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 during 2003 and therefore the financial results for the assets were reflected as 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 on 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.

        Net Income (Loss).    Our net income increased to $2.8 million in 2003 as restated from a net loss of $1.2 million in 2002 as restated. This improvement was due primarily to our substantial increase in revenue and margins in 2003 compared to 2002, partially offset by the write-off of

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approximately $5.2 million loss on the early extinguishment of debt due to the two refinancings of our indebtedness in 2003. As part of our October 2003 refinancing, all of our outstanding mandatorily redeemable preferred stock was converted to common stock. Before this conversion, we incurred accrued dividends and accretion of preferred stock discount of $1.4 million in 2002 and $2.1 million in 2003. These amounts reduced our net income available to common stockholders to a net loss of $2.7 million in 2002 as restated and net income of $769,000 in 2003 as restated.

Liquidity and Capital Resources

        Currently, our primary capital resources are net cash flows from our operations, utilization of capital leases as allowed under our credit facility and availability under our credit facility, of which approximately $41.7 million was available at June 30, 2005. As of June 30, 2005, we had cash and cash equivalents of $14.1 million compared to $13.9 million as of June 30, 2004. 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 $44.8 million for the six months ended June 30, 2005 as compared to $19.7 million during the same period in 2004, and was $46.5 million in 2004 as compared to $29.8 million in 2003 and $17.0 million in 2002. The increase in operating cash flows during the first six months of 2005 over the same period in 2004 was primarily due to improvements in the segment profits and utilization of our equipment. The increase in operating cash flows in 2004 over 2003 was primarily due to (1) improvements in the segment profits and utilization of our equipment and (2) our acquisitions in 2003. The 2003 operating cash flows, as compared to 2002, increased as a result of our acquisitions, and an increase in our segment profits and utilization. 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.

Capital Expenditures

        Capital expenditures are the main component of our investing activities. Cash capital expenditures (including for acquisitions) for the six months ended June 30, 2005 were $45.4 million as compared to $29.4 million for the same period in 2004, and were $75.0 million in 2004 as compared to $85.4 million in 2003 and $45.7 million in 2002. During the first six months of 2005, the majority of our capital expenditures were for the expansion of our fleet. In 2004, the majority of the capital expenditures were for the expansion of our fleet, whereas in 2003 the majority 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 $84.9 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 $3.6 million during the first six months of 2005, and $10.5 million, $10.8 million and $2.4 million in 2004, 2003 and 2002, respectively.

        For 2005, we currently have planned approximately $57 million in capital expenditures, none of which is planned for acquisitions. We do not budget acquisitions in the normal course of business, but we believe that we may spend a significant amount for acquisitions in 2005. The $57 million of capital expenditures planned for property and equipment is primarily for (1) purchase of additional equipment to expand our services in certain regions, (2) continued refurbishment of our well servicing rigs and (3) replacement of existing equipment. During the first six months of 2005, we spent an aggregate of $35.5 million on these capital expenditures. As of June 30, 2005, we had

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executed letters of intent for acquisitions providing for an aggregate cash purchase price, including potential future payments, of approximately $14.0 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.

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 $12.5 million at June 30, 2005, the availability under our credit facility of $41.7 million at June 30, 2005 and a cash balance of $14.1 million at June 30, 2005. In 2004, we financed activities in excess of cash flow from operations primarily through the use of bank debt and capital loans. During 2003 and 2002, 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) our other long-term liabilities. The following table outlines our contractual obligations as of December 31, 2004 (in thousands):

		Obligations Due in Periods Ended December 31,
Contractual Obligations
		Total		2005		2006-2007		2008-2009		Thereafter
Long-term debt (excluding capital leases)		$	166,500	$	7,000	$	21,000	$	138,500	$	—
Capital leases			15,976		4,561		8,159		3,256		—
Operating leases			3,191		818		1,017		641		715
Rig purchase obligations			13,000		13,000		—		—		—
Asset retirement obligations			473		—		—		—		473
Other long-term liabilities			522		379		135		8		—
	Total	$	199,662	$	25,758	$	30,311	$	142,405	$	1,188

        Our long-term debt, excluding capital leases, consists primarily of term loan indebtedness outstanding under our senior 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.

        The table above does not reflect any additional payments that we may be required to make pursuant to contingent earn-out agreements that are associated with certain acquisitions. At December 31, 2004, we had a maximum potential obligation of $5.7 million related to the contingent earn-out agreements. See note 3 of the notes to our historical consolidated financial statements for additional detail.

        The table above also does not reflect $8.3 million of outstanding standby letters of credit issued under our revolving line of credit that expire during 2005. At June 30, 2005, of the $50.0 million in financial commitments under the revolving line of credit under our senior credit facility, there was only $41.7 million of available capacity due to the $8.3 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.

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        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.

Credit Facilities

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 provides for a $170 million Term B Loan ("2004 Term B Loan") and a $50 million revolving line of credit ("Revolver"). The commitment under the Revolver allows 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 require 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 Revolver are due and payable on October 3, 2008. The 2004 Credit Facility is 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.

        At our option, borrowings under the 2004 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 2.0% or (2) the LIBOR rate plus 3.0%. At June 30, 2005, our weighted average interest rate on the 2004 Term B Loan was 5.55%. At June 30, 2005, $163.2 million was outstanding under the 2004 Term B Loan, including approximately $196,000 of accrued interest.

        At our option, borrowings under the Revolver bear interest at either (1) the Alternative Base Rate plus a margin ranging from 1.50% to 2.00% or (2) the LIBOR rate plus a margin ranging from 2.50% to 3.00%. The margins vary depending on our leverage ratio. At June 30, 2005, our margin on Alternative Base Rates and LIBOR tranches was 2.00% and 3.00%, respectively. Fees on the letters of credit are due quarterly on the outstanding amount of the letters of credit at a rate ranging from 2.50% to 3.00% 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 .50%.

        At June 30, 2005, we had outstanding $8.3 million of letters of credit under the Revolver and no amounts outstanding in swing-line loans under the Revolver. At June 30, 2005, we had availability under the Revolver of $41.7 million and no principal balance outstanding.

        Pursuant to the 2004 Credit Facility, we must apply proceeds from certain specified events to reduce principal outstanding under the Revolver, including:

•

assets sales greater than $1.0 million individually or $5.0 million in the aggregate on an annual basis; and



•

50% of the proceeds from any equity offering.

        The 2004 Credit Facility required us to enter into an interest rate hedge, acceptable to the lenders, for at least two years on at least $65 million of our then-outstanding indebtedness. See the notes to our historical consolidated financial statements discussing the interest rate hedge. Repayments on the Term B Loan may not be reborrowed.

        The 2004 Credit Facility contains various restrictive covenants and compliance requirements, including the following:

•

limitations on the incurrence of additional indebtedness;



•

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

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•

limitation on dividends and distributions; and



•

various financial covenants, including as of June 30, 2005:



•

a maximum leverage ratio of 3.25 to 1.00 reducing to 3.00 to 1.00,



•

a minimum fixed charge coverage ratio of 1.15 to 1.00, and



•

a minimum interest coverage ratio of 3.00 to 1.00.

        At June 30, 2005, we were in compliance with all covenants.

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 current 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 December 31, 2004, we had total capital leases of approximately $16.0 million.

Losses on Extinguishment of Debt

        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 facility related to 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.

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Credit Rating Agencies

        We have received credit ratings of B1 from Moody's and B from Standard & Poor's for our long-term debt under the 2004 Credit Facility. 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 $12.2 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 $27.1 million NOL, including $7.0 million that was included in the purchase of FESCO. As of December 31, 2004, we had approximately $55.9 million of NOL carryforward. Approximately $7.0 million of the NOL relates 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. Accordingly, we have significant NOLs to shelter future taxable income, but our ability to utilize our NOLs may be limited by the alternative minimum tax, and the use of the NOL attributable to FESCO prior to its acquisition by us will be limited by the change of control that occurred at that time.

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 will adopt 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 canceled 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 under APB No. 25. We will recognize compensation expense for awards under our Amended and Restated 2003 Incentive Plan (the "Incentive Plan") beginning 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. 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

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number of shares purchased under the Incentive Plan. Further, we have not yet determined the actual model we will use 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 credit facility. We had a total of $166.5 million of indebtedness outstanding under our credit facility at December 31, 2004. 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 $1.7 million annually, or a decrease in net income of approximately $1.0 million. Our market risks at June 30, 2005 were similar to those disclosed for the year ended December 31, 2004.

        We do not hold or issue derivative instruments for trading purposes. We do, however, have an interest rate derivate instrument that has been formally designated as a cash flow hedge instrument. This instrument effectively converts the variable interest payments on $65 million of our 2004 Term B Loan into fixed interest payments.

        The table below provides scheduled principle payments and fair value information about our market-risk sensitive instruments as of December 31, 2004 (dollars in thousands):

	Expected Year of Maturity
	2005		2006		2007		2008		2009		Total		Fair Value
Debt
Variable rate	$	7,000	$	10,500	$	10,500	$	14,000	$	124,500	$	166,500	$	166,500
Average interest rate(1)

	Average Notional Amounts Outstanding(2)
	2005			2006			2007	2008	2009	Total			Fair Value
Interest Rate Derivatives
Variable to Fixed	$	65,000		$	26,356		$—	$—	$—	$	91,356		$	29
Average pay rate		3.03	%		3.03	%	—	—	—		3.03	%		N/A
Average received rate		3.25	%		4.00	%	—	—	—		3.63	%		N/A

(1)

At our option, borrowings under the Revolver bear 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 vary depending on our leverage ratio. At December 31, 2004, our margin on Alternative Base Rates and LIBOR tranches was 2.0% and 3.0%, 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 June 21, 2005.

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BUSINESS

General

        We provide a wide range of well site services to oil and gas drilling and producing companies, including well servicing, fluid services, drilling and completion services and well site construction services. These services are fundamental to establishing and maintaining the flow of oil and gas throughout the productive life of a well. Our broad range of services enables us to meet multiple needs of our customers at the well site. Our operations are managed regionally and are concentrated in the major United States onshore oil and gas producing regions in Texas, New Mexico, Oklahoma, Louisiana and in 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 over 10% of the overall available U.S. fleet with our two larger competitors controlling approximately 31% and 18%, respectively, according to the Association of Energy Services Companies.

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

•

Well Servicing.  Our well servicing segment (48% of our revenues for the first six months of 2005) currently operates our fleet of over 300 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 (30% of our revenues for the first six months of 2005) currently utilizes our fleet of over 400 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 (12% of our revenues for the first six months of 2005) currently operates our fleet of 37 pressure pumping units, 20 air compressor packages specially configured for underbalanced drilling operations and 11 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.



•

Well Site Construction Services.  Our well site construction services segment (10% of our revenues for the first six months of 2005) 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.

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Our Competitive Strengths

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

        Significant Market Position.    We maintain a significant market share for our well servicing operations in our core operating areas throughout Texas and a growing market share in the other markets that we serve. Our fleet of over 300 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 56 of our rigs are either 2000 model year or newer, or have undergone major refurbishments during the last four years. As of June 30, 2005, we have taken delivery of 19 newbuild well servicing rigs since October 2004 as part of a 54-rig newbuild commitment. The remainder of these newbuilds will be delivered prior to the end of May 2006. 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 44 of our rigs since the beginning of 2001. Approximately 98% of our fleet was active or available for work and the remainder was awaiting refurbishment at June 30, 2005. We believe only approximately 62% of the well servicing rig fleet of our two major competitors are active and available for work. During 2003 and 2004, we obtained 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, Louisiana and the Rocky Mountain states. We operate in states that accounted for approximately 60% of the more than 900,000 existing onshore oil and gas wells in the 48 contiguous states and approximately 70% of onshore oil and gas production in 2004. 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.    We believe our range of well site services provides us a competitive advantage over smaller companies that typically offer fewer services. Our experience, equipment and network of 68 service locations position us to market our full range of well site services to our existing customers. By utilizing a wider range of our services, our customers can use fewer service providers, which enables them to reduce their administrative costs and simplify their logistics. Furthermore, offering a broader range of services allows us to capitalize on our existing customer base and management structure to grow within existing markets, generate more business from existing customers, and increase our operating profits as we spread our overhead costs over a larger revenue base.

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

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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 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 managers, our 65 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

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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 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, which decisions may involve a combination of asset acquisitions and the purchase of new equipment. During 2005, we have completed six separate acquisitions for an aggregate purchase price of $11.4 million, including future potential payments, and have taken delivery of 15 new well servicing rigs as of June 30, 2005.

General Industry Overview

        Demand for services offered by our industry is a function of our customers' willingness to make 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:

•

As oil and gas prices have rebounded beginning in early 1999, total expenditures for all U.S. exploration and production activities (including offshore activities that we do not serve) have increased to an estimated $56 billion in 2003 and $62 billion in 2004 and are expected to reach $66 billion in 2005, according to Oil & Gas Journal in April 2005.



•

A survey of 16 U.S. major integrated and 102 independent oil and gas companies by World Oil Magazine projects the U.S. drilling activity in 2005 to be skewed more towards independent players, as the number of wells drilled by the major producers in 2005 is expected to increase 19.4%, whereas independent companies, which represent over 90% of our revenue, are expected to drill almost 50% more wells in 2005 than in 2004. 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 that have rebounded since 1999. The table below sets forth average daily closing prices for the Cushing WTI

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Spot Oil Price and the Energy Information Agency average wellhead price for natural gas since 1999:

Period	Cushing WTI Spot Oil Price ($/bbl)		Average Wellhead Price Natural Gas ($/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 - 6/30/05		51.54		5.95

Source: U.S. Department of Energy.

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

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

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

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

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

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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 includes 308 well service rigs as of June 30, 2005, including 19 newbuilds since October 2004 and 44 rebuilds since the beginning of 2001. We operate from 68 facilities in Texas, Wyoming, Oklahoma, North Dakota, New Mexico, Louisiana, Colorado and Montana, most of which are used jointly for our business segments. Our rigs are mobile units that generally operate within a radius of approximately 75 to 100 miles from their respective bases. Prior to December 2004, our well servicing segment consisted entirely of land-based equipment. During December 2004, we acquired three inland barges, two of which are equipped with rigs, have been refurbished and were placed into service in the second quarter of 2005. Inland barges are used to service wells in shallow water marine environments, such as coastal marshes and bays.

        The following table sets forth the location, characteristics and number of the well servicing rigs that we operated at June 30, 2005. 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 35 new well servicing rigs that we have contracted for delivery during July 2005 through May 2006 as part of a 54-rig commitment:

			Operating Division
Rig Type		Rated Capacity	Permian Basin	North Texas	South Texas	Ark-La- Tex	Mid- Continent	Northern Rockies	Southern Rockies	Stacked	Houma Lou.	Total
Swab		N/A	3	1	1	8	2	0	0	0	0	15
Light Duty		<90 tons	8	25	2	0	1	2	0	3	0	41
Medium Duty		>90; <125 tons	87	18	32	14	17	13	9	2	0	192
Heavy Duty		³125 tons	27	0	4	6	5	6	3	2	0	53
24-Hour		³125 tons	1	0	3	0	0	0	1	0	0	5
Inland Barge		³125 tons	0	0	0	0	0	0	0	0	2	2
	Total		126	44	42	28	25	21	13	7	2	308

        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

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Weatherford-AESC, there were 2,477 well servicing rigs working in June 2005. This figure represents a projected utilization rate of 90% 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 2,234 rigs of which 1,349 are operated and 885 are stacked. These two competitors' total rigs represent approximately 64% of the industry's total fleet. We have the third largest fleet with over 300 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 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.

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        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;

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•

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



•

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



•

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

        This segment utilizes our fleet of fluid services trucks and related assets, including specialized tank trucks, portable storage tanks, water wells, disposal facilities and related equipment. The following table sets forth the type, number and location of the fluid services equipment that we operated at June 30, 2005:

	Operating Division
	Northern Rockies	Permian Basin	Ark-La- Tex	South Texas	North Texas	Mid- Continent	Southern Rockies	Total
Fluid Services Trucks	92	120	98	106	17	20	—	453
Salt Water Disposal Wells	—	9	8	7	5	3	—	32
Fresh/Brine Water Stations	—	28	—	2	—	—	—	30
Fluid Storage Tanks	210	256	381	229	2	73	—	1,151

        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.

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        Fluid Services and Support Trucks.    We currently own and operate over 400 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; and



•

underbalanced drilling in low pressure and fluid sensitive reservoirs.

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        This segment currently operates 37 pressure pumping units to conduct a variety of services designed to stimulate oil and gas production or to enable cement slurry to be placed in or circulated within a well. As of June 30, 2005, we also operate 20 air compressor packages, including foam circulation units, for underbalanced drilling and 11 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.

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        The following table sets forth the type, number and location of the drilling and completion services equipment that we operated at June 30, 2005:

	Operating Division
	Ark-La- Tex	Gulf Coast	Mid- Continent	North Texas	Permian Basin	Northern Rockies	Southern Rockies	South Texas	Total
Pressure Pumping Units	11	—	—	23	—	3	—		37
Coiled Tubing Units	—	—	—	3	—	—	—	—	3
Air/Foam Packages	—	—	—	—	—	—	20	—	20
Wireline Units	—	—	—	11	—	—	—	—	11

        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.

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        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.

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 County, Texas 79701. We have also recently purchased and are renovating a facility in Midland, Texas to consolidate our corporate office and to expand our refurbishment capacities. We currently conduct our business from 68 area offices, 31 of which we own and 37 of which we lease. Each office typically includes a yard, administrative office and maintenance facility. Of our 68 area offices, 45 are located in Texas, five are in Wyoming, five are in Oklahoma, three are in New Mexico, three are in Louisiana, three are in Colorado, two are in Montana and two are in North Dakota.

Customers

        We serve numerous major and independent oil and gas companies that are active in our core areas of operations. During the first six months of 2005, we provided services to more than 1,000

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customers, with our top five customers comprising only 17% of our revenues. The majority of our business is with independent oil and gas companies. While we believe we could redeploy equipment in the current market environment if we lost a single material customer, or a few of them, such loss could have an adverse effect on our business until the equipment is redeployed.

Operating Risks and Insurance

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

•

personal injury or loss of life;



•

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



•

suspension of operations.

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

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

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

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

Competition

        Our competition includes small regional contractors as well as larger companies with international operations. Our two largest competitors, Key Energy Services, Inc. and Nabors Well Services Co., combined own approximately 64% of the well service market share based on well servicing rig ownership. 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

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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

        In recent years, many of our larger customers have placed an emphasis not only on pricing, but also on safety records and the quality management systems of 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 joint and several liability for the costs of investigating and cleaning up

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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 are in the process of updating SPCC plans for several of our facilities and currently expect to complete and implement these plans by the end of 2005. 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

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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 June 30, 2005, we employed approximately 3,000 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.

Legal Proceedings

        On September 3, 2004, David Hudson, Jr. et al commenced a civil action against us in the District Court of Panola County, Texas, 123^rd 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. In response

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to the complaint, we have retained counsel and filed a general denial. We are in the beginning stages of discovery and trial has been tentatively scheduled for January or February 2006. We intend to defend ourselves vigorously in this action.

        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 has denied coverage of liability in this lawsuit. We have accrued a loss of $1.3 million, including interest, for this contingency as of June 30, 2005. We plan to appeal this verdict and may pursue coverage claims with our insurer.

        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.

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MANAGEMENT

Directors, Executive Officers and Other Key Employees

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

Name	Age	Position
Steven A. Webster	53	Chairman of the Board
Kenneth V. Huseman	53	President, Chief Executive Officer and Director
James J. Carter	60	Executive Vice President and Secretary
Alan Krenek	50	Vice President, Chief Financial Officer and Treasurer
Dub W. Harrison	47	Vice President — Equipment & Safety
Mark D. Rankin	52	Vice President — Business Development
James E. Tyner	55	Vice President — Human Resources
Charles W. Swift	56	Vice President — Permian Basin
James S. D'Agostino, Jr.	58	Director
William E. Chiles	56	Director
Robert F. Fulton	54	Director
Sylvester P. Johnson, IV	49	Director
H. H. Wommack, III	49	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., 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 First Boston's Alternative Capital Division that made investments in energy companies, from 1999 until June 30, 2005. Mr. Webster has been engaged by Credit Suisse First Boston's Alternative Capital Division as a consultant. As a consultant to Credit Suisse First Boston, Mr. Webster continues to serve on the boards of, and monitor the operations of, various existing portfolio companies of Credit Suisse First Boston's Alternative Capital Division, 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., 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. At Key Energy Services, Mr. Huseman expanded the number of rigs from less than 200 to 1,400, the shallow drilling business from 4 to 78 rigs and executed over 50 acquisitions. He was a Divisional Vice President at WellTech, Inc., from 1993 to 1996 where he closed two acquisitions for a total of 42 rigs, moved WellTech from the second largest to the largest player in the market and

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started a turnaround of operations in Argentina. 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.

James J. Carter (Executive Vice President and Secretary) has spent 24 years in the well services industry. He has been our Executive Vice President since January 2005. Served as our Chief Financial Officer from December 2000 until January 2005. From 1999 to 2000, Mr. Carter worked in a consulting and brokerage capacity, with a well services industry specialization. He worked at another well servicing company in financial management from 1996 to 1999, where he managed the financial turnaround of its Argentina operations, negotiated and closed acquisitions in various domestic markets and negotiated insurance coverages and vehicle leases. He worked in financial management positions at Pool Energy Services Co. from 1978 to 1993, where he managed operations analysis and financial support at the corporate level and managed financial operations in California and south Texas. Mr. Carter graduated with a B.S. degree in Accounting from Indiana University and an M.B.A. from Memphis University.

        Alan Krenek (Vice President, Chief Financial Officer and Treasurer) has 17 years of related industry experience. He has been our Vice President, Chief Financial Officer and Treasurer since January 2005. 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.

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 — Business Development) 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

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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.

Charles W. Swift (Vice President — Permian) has 33 years of related industry experience including 25 years specifically in the domestic well service business. He has been 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.

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 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.

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        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 seven members, including three independent members — Messrs. D'Agostino, Chiles 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 additional independent directors to our board of directors following the completion of this offering.

        Our board of directors will be divided into three classes. The directors will serve staggered three-year terms. The initial terms of the directors of each class will expire at the annual meetings of stockholders to be held in 2006 (Class I), 2007 (Class II) and 2008 (Class III). At each annual meeting of stockholders, one class of directors will be elected for a full term of three years to succeed that class of directors whose terms are expiring. The classification of directors will be as follows:

•

Class I — Messrs. Johnson, Webster and Wommack;



•

Class II — Messrs. Chiles and Fulton; and



•

Class III — Messrs. D'Agostino and Huseman.

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 corporate governance and nominating and compensation committees will be independent within 90 days of listing on the NYSE and, within one year, these committees will be fully independent and a majority of our board will be independent. A majority of the directors on our audit committee will be independent within 90 days of the effectiveness of the registration statement and, within one year of effectiveness, the committee will be fully independent.

Audit Committee

        Our audit committee is currently comprised of Messrs. D'Agostino, Chiles and Fulton. Our board has determined that Messrs. D'Agostino and Chiles 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. Rule 10A-3 under the Exchange Act and the listing requirements of the NYSE require that our audit committee be composed of a majority of independent directors within 90 days of the effectiveness of the registration statement of which this prospectus is a part and that it be composed solely of independent directors within one year of such date. Accordingly, we intend to appoint an additional independent director to our audit

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committee to replace Mr. Fulton following the consummation of the offering. Following this offering, one member of the audit committee will be designated as the audit committee financial expert, as defined by Item 401(h) of Regulation S-K of the Exchange Act. The principal duties of the audit committee will be as follows:

•

to review our external financial reporting;



•

to engage our independent auditors; and



•

to review our procedures for internal auditing and the adequacy of our internal accounting controls.

        Our board of directors has adopted a written charter for the audit committee that will be available on our website after the closing of this offering.

Nominating and Corporate Governance Committee

        Our nominating and corporate governance committee currently consists of Messrs. Johnson, Webster and Fulton. Our board has determined that Mr. Johnson is independent as required by the listing requirements of the NYSE. The listing requirements of the NYSE require that our nominating and corporate governance committee be composed of a majority of independent directors within 90 days of the listing of our common stock on the NYSE and that it be composed solely of independent directors and have at least three members within one year of such date. Accordingly, we intend to appoint additional independent directors to our nominating and corporate governance committee to replace Messrs. Webster and Fulton following the consummation of the offering. The principal duties of the nominating and corporate governance committee will be as follows:

•

to recommend to the board of directors proposed nominees for election to the board of directors by the stockholders at annual meetings, including an annual review as to the renominations of incumbents and proposed nominees for election by the board of directors to fill vacancies that occur between stockholder meetings; and



•

to make recommendations to the board of directors regarding corporate governance matters and practices.

        Our board of directors has adopted a written charter for the corporate governance and nominating committee that will be available on our website after the closing of this offering.

Compensation Committee

        Our compensation committee currently consists of Messrs. Chiles, D'Agostino and Wommack. Our board has determined that Messrs. Chiles and D'Agostino are independent as required by the listing requirements of the NYSE. The listing requirements of the NYSE require that our compensation committee be composed of a majority of independent directors within 90 days of the listing of our common stock on the NYSE and that it be composed solely of independent directors within one year of such date. Accordingly, we intend to appoint an additional independent director to our compensation committee to replace Mr. Wommack following the consummation of the offering. The principal duties of the compensation committee will be as follows:

•

to administer our stock plans and incentive compensation plans, including our 2003 Incentive Plan, and in this capacity, make all option grants or awards to our directors and employees under such plans;



•

to make recommendations to the board of directors with respect to the compensation of our chief executive officer and our other executive officers; and



•

to establish compensation and employee benefit policies.

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        Our board of directors has adopted a written charter for the compensation committee that will be available on our website after the closing of this offering.

Web Access

        We will 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 our four other most highly compensated executive officers during the year ended December 31, 2004, to whom we refer in this prospectus as our named executive officers. The following table does not include Alan Krenek, our Chief Financial Officer who joined us in January 2005.

Summary Compensation Table

		Annual Compensation(1)				Long-Term Compensation(1)
	Year	Salary		Bonus		Restricted Stock Awards($)(2)		Securities Underlying Options (#)	All Other Compensation(3)
Kenneth V. Huseman	2004	$	327,884	$	500,000	$	3,141,000	—	$	2,308
James J. Carter	2004	$	168,846	$	200,000	$	698,000	—	$	—
Charles W. Swift	2004	$	151,924	$	69,894	$	349,000	—	$	9,600
Dub W. Harrison	2004	$	141,539	$	60,250	$	349,000	—	$	9,600
James E. Tyner	2004	$	101,538	$	11,197	$	—	—	$	26,519
Darin G. Holderness(4)	2004	$	103,261	$	5,250	$	—	—	$	—

(1)

Under the terms of their employment agreements, Messrs. Huseman, Carter, Swift, Harrison and Tyner are entitled to the compensation described under "— Employment Agreements" below.

(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 vest 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."

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(3)

Includes: for Mr. Huseman, a vehicle allowance of $2,308; for each of Mr. Swift and Harrison, a vehicle allowance of $9,600; and for Mr. Tyner, moving-related allowances of $26,519.

(4)

Mr. Holderness served as our Vice President — Finance and Treasurer from March to November 2004.

Aggregated Option Exercises in 2004 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, 2004 by each of the named executive officers. None of the named executive officers exercised options during the year ended December 31, 2004. Because there was no public market for our common stock as of December 31, 2004, amounts described in the following table under the heading "Value of Unexercised In-the-Money Options at December 31, 2004" are determined by multiplying the number of shares issued or issuable upon the exercise of the option by the difference between the assumed initial public offering price of $    per share and the per share option exercise price.

	Number of Shares Underlying Unexercised Options at December 31, 2004		Value of Unexercised In-the-Money Options at December 31, 2004
	Exercisable	Unexercisable	Exercisable	Unexercisable
Kenneth V. Huseman	333,105	133,300	$	$
James J. Carter	108,720	40,000
Dub W. Harrison	72,895	33,330
Charles W. Swift	72,895	33,330
James E. Tyner	—	25,000

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

•

stock options;

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•

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 3,273,300 shares have been issued as of June 30, 2005. 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

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respect to the grant of a non-qualified stock option. Upon exercise of a non-qualified stock option, the excess of the fair market value of the common stock transferred to the optionee over the option exercise price will be taxable as compensation income to the optionee and will be subject to applicable withholding taxes. Such fair market value generally will be determined on the date the shares of common stock are transferred pursuant to the exercise. We generally will be entitled to a federal income tax deduction at such time in the amount of such compensation income. The optionee's federal income tax basis for the common stock received pursuant to the exercise of a non-qualified stock option will equal the sum of the compensation income recognized and the exercise price. In the event of a sale of common stock received upon the exercise of a non-qualified stock option, any appreciation or depreciation after the exercise date generally will be taxed as capital gain or loss.

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

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

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

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

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

Employment Agreements

        Under our prior employment agreement with Mr. Huseman through April 30, 2004, Mr. Huseman had a minimum annual salary of $250,000 and an annual bonus ranging from $50,000 to $250,000 based on the level of performance objectives achieved by us. Under this employment agreement, Mr. Huseman received a grant of 45,530 shares of stock in 1999. Under this agreement, as amended, Mr. Huseman received additional grants during 2000 of an additional 19,510 shares that were subject to forfeiture and forfeited and 65,040 shares of restricted stock that vest on anniversaries of his employment commencement date or earlier upon certain qualified terminations of his employment, 19,510 shares of which were subject to forfeiture and forfeited.

        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 2004 was unanimously approved by our Board of Directors, including the independent directors. Notwithstanding the contractual range for an annual bonus under the terms of his employment agreement, in 2004 the Board of Directors approved the payment of a $300,000 bonus to Mr. Huseman in accordance with this agreement in recognition of our performance against expectations, and the Board of Directors designated an additional $200,000 payment as a special, non-recurring bonus in recognition of the substantial growth achieved during the year, including the closing of two significant acquisitions that opened new markets for us.

        We have also entered into employment agreements with Dub W. Harrison, Charles W. Swift, James J. Carter and James E. Tyner through April 2006. Mr. Harrison is entitled to an annual salary of $120,000, Messrs. Swift and Carter are each entitled to an annual salary of $130,000 and Mr. Tyner is entitled to an annual salary of $110,000. Under these agreements, if the officer's employment is terminated for certain reasons, he would be entitled to a lump sum severance payment equal to six months' salary, or 18 months' salary (or 36 months' salary in the case of Mr. Carter or 12 months' salary in the case of Mr. Tyner) if termination is on or following a change of control of our company.

        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

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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 has already 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, or 18 months' salary if termination is on or following a change of control of our company.

Indemnification Agreements

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

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

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

•

us, except for:



•

claims regarding the indemnitee's rights under the indemnification agreement;



•

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



•

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



•

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

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

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CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

Transactions with Officers and Directors

        We performed well servicing and fluid services for Southwest Royalties, Inc. in exchange for $800,000, $1.3 million and $140,000 for the years ended 2002, 2003 and 2004, 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 will enter into Share Tender and Repurchase Agreements with ten of our officers. In these agreements, we will agree to repurchase, and the officers will agree to sell, an aggregate of up to 167,583 shares of our common stock at the initial public offering price, less underwriting discounts and commissions, on the closing date of this offering. These shares are being 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 being repurchased represent up to 39.2% of the vested shares of each officer issued as compensation. We will withhold minimum tax liability requirements from these proceeds and pay the remainder of the proceeds to the officers for their use in paying estimated tax liabilities. The four executive officers and maximum number of shares that we will repurchase from them upon the closing of this offering are as follows: Kenneth V. Huseman — 101,975 shares; James J. Carter — 27,327 shares; Dub W. Harrison — 10,688 shares; and Charles W. Swift — 10,688 shares. The remaining six officers are not executive officers.

        In addition to the repurchase of shares on the closing date of this offering, we will agree under the Share Tender and Repurchase Agreements to repurchase, and the officers will irrevocably agree to sell, up to an aggregate of 84,068 shares of our common stock on February 24, 2006 at the closing price per share of common stock on that date. These shares are also being 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 represent up to 36.45% of the restricted shares owned by each officer that vest on that date. We will withhold minimum tax liability requirements from these proceeds and pay the remainder of the proceeds to the officers for their use in paying estimated tax liabilities. The four executive officers and maximum number of shares that we will repurchase from them on February 24, 2006 are as follows: Kenneth V. Huseman — 41,007 shares; James J. Carter — 18,225 shares; Dub W. Harrison — 4,557 shares; and Charles W. Swift — 4,557 shares.

Transactions with DLJ Merchant Banking

        In December 2000, we completed a private recapitalization by DLJ Merchant Banking, which gained majority control of us. The funds comprising DLJ Merchant Banking are part of DLJ Merchant Banking Partners, which is a private equity investor with a 20-year history of investing in leveraged buyouts and related transactions across a broad range of industries. DLJ Merchant Banking Partners is part of Credit Suisse First Boston's Alternative Capital Division, Credit Suisse First Boston's dedicated alternative asset platform.

        Since December 2000, DLJ Merchant Banking has contributed approximately $81 million through several equity investments and has been instrumental in providing and arranging capital to drive our growth. 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. DLJ Merchant Banking currently beneficially owns approximately 73.1% of our outstanding common stock (or 76.6% on a diluted basis giving effect to the exercise of warrants held by these funds). DLJ Merchant Banking and its affiliated funds are selling shares of our common stock in this offering. See "Selling Stockholders." Following the consummation of this offering, DLJ Merchant Banking will

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beneficially own approximately             % of our outstanding common stock (or             % if the underwriters' over-allotment option is exercised in full).

        Pursuant to the terms of our stockholders' agreement among us, DLJ Merchant Banking and our other stockholders, DLJ Merchant Banking had the right to designate a majority of the members of our Board of Directors. After the completion of this offering, representatives originally designated by DLJ Merchant Banking will continue to compose a majority of our Board of Directors, but DLJ Merchant Banking will no longer have the right to designate members of our Board of Directors.

        Subject to certain restrictions, the stockholders' agreement also provides DLJ Merchant Banking 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 this 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). We have agreed to pay most offering fees and expenses associated with the registration and offering of these shares, other than underwriting fees, discounts or commissions. We have also agreed to indemnify these stockholders and their officers, directors, partners, legal counsel and other listed representatives against certain losses, claims, damages or liabilities in connection with the registered offering of their 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

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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. Going forward, we expect to address transactions involving potential conflicts of interest by having such transactions approved by the disinterested members of our Board of Directors.

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PRINCIPAL STOCKHOLDERS

        The following table sets forth information with respect to the beneficial ownership of our common stock as of June 30, 2005 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 (13 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 number and percentage of shares beneficially owned after this offering does not include the effects of any exercise of the underwriters' option to purchase additional shares.

	Shares Beneficially Owned Prior to this Offering			Shares Beneficially Owned After this Offering
Name of Beneficial Owner
	Number	Percent		Number	Percent
DLJ Merchant Banking Partners III, L.P. and affiliated funds(1)	25,486,280	76.6	%	19,528,910		%
First Reserve Fund VIII, L.P.(2)	3,371,175	11.7	%	2,583,169
Fortress Holdings, LLC(3)(4)	941,590	3.3	%	721,495		%
Anchor Resources, LLC(3)(4)	2,024,340	7.0	%	1,551,155		%
Kenneth V. Huseman(5)	1,123,950	3.8	%			%
James J. Carter(6)	248,430	*			*
Dub W. Harrison(7)	160,590	*			*
Charles W. Swift(8)	154,325	*			*
James E. Tyner(9)	8,335	*		8,335	*
Steven A. Webster(10)	52,500	*		52,500	*
James S. D'Agostino, Jr.(11)	15,835	*		15,835	*
William E. Chiles(12)	17,500	*		17,500	*
Robert F. Fulton(10)	52,500	*		52,500	*
Sylvester P. Johnson, IV(10)	52,500	*		52,500	*
H.H. Wommack, III(3)(4)(13)	3,018,430	10.4	%			%
Directors and Executive Officers as a Group (13 persons)(14)	4,904,895	16.4	%			%

*

Less than one percent.

(1)

Includes 21,136,280 shares of common stock and 4,350,000 shares of common stock issuable upon exercise of warrants owned by DLJ Merchant Banking and its affiliates as follows: DLJ Merchant Banking Partners III, L.P. (14,759,195 shares and warrants exercisable for

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3,093,225 shares); DLJ ESC II, L.P. (2,107,250 shares); DLJ Offshore Partners III, C.V. (600,030 shares and warrants exercisable for 29,195 shares); DLJ Offshore Partners III-1, C.V. (37,655 shares and warrants exercisable for 7,530 shares); DLJ Offshore Partners III-2, C.V. (26,820 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. (432,245 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. (228,695 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. (162,920 shares and warrants exercisable for 34,395 shares); DLJMB Partners III GmbH & Co. KG (125,890 shares and warrants exercisable for 26,380 shares); DLJMB Funding III, Inc. (186,595 shares); Millennium Partners II, L.P. (25,060 shares and warrants exercisable for 5,305 shares); MBP III Plan Investors, L.P. (2,443,925 shares and warrants exercisable for 913,500 shares).

Credit Suisse, a Swiss bank (the "Bank"), owns the majority of the voting stock of Credit Suisse First Boston, Inc., a Delaware corporation which in turn owns all of the voting stock of Credit Suisse First Boston (USA) Inc., a Delaware corporation ("CSFB-USA"). The entities discussed in the above paragraph are merchant banking funds managed by indirect subsidiaries of CSFB-USA and form part of Credit Suisse First Boston's Alternative Capital Division. The ultimate parent company of the Bank 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 First Boston's Alternative Capital Division, from 1999 until June 30, 2005 and remains a consultant to Credit Suisse First Boston's Alternative Capital Division.

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)

Includes 337,120 shares currently held in escrow as security for certain of its indemnification obligations pursuant to its Escrow Agreement with us and Amegy, N.A., as the escrow agent. As the record owner of these securities, First Reserve Fund VIII, L.P. is entitled to exercise all voting rights with respect to these shares. First Reserve GP VIII, L.P. ("GP VIII") is the general partner of First Reserve Fund VIII, L.P. First Reserve Corporation is the general partner of GP VIII. The officers who make decisions for GP VIII and First Reserve Corporation are William E. Macaulay, John A. Hill, Ben A. Guill, Thomas R. Denison, J.W.G. (Will) Honeybourne, Alex T. Krueger, Thomas J. Sikorski, Cathleen Ellsworth, Jennifer C. Zarrilli, Craig M. Jarchow, Kenneth W. Moore, Catia Cesari, Timothy H. Day, Joseph R. Edwards, Mark A. McComiskey, J. Hardy Murchison, Glenn J. Payne, Kristin A. Custar, Brian K. Lee, Bing Feng Leng, Timothy K. O'Keeffe, Anne E. Gold, Valerie A. Thomason and Damien T.J. Harris, all of whom are employees of First Reserve Corporation. Certain other decisions are made by the Investment Committee of First Reserve Corporation, made up of a subset of these officers. The address of GP VIII and First Reserve Corporation is c/o First Reserve Corporation, One Lafayette Place, Greenwich, CT 06830.

(3)

Fortress Holdings, LLC, successor in interest to Southwest Royalties Holdings, Inc., directly owns 941,590 shares, or 3.3% of total shares outstanding before the offering. 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,

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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 673,680 shares owned directly by Southwest Partners II, L.P. and 1,350,660 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 450,000 shares of restricted stock, of which 337,500 remain subject to vesting in one-third increments on February 24, 2006, 2007 and 2008, and 399,755 shares issuable within 60 days upon the exercise of options granted under our 2003 Incentive Plan. Does not include 166,650 shares underlying options that are not exercisable within 60 days granted under our 2003 Incentive Plan. Shares beneficially owned after this offering does not give effect to the potential sale of up to 25,000 shares that may be sold pursuant to the exercise of the underwriters' over-allotment option. Shares beneficially owned after this offering give effect to             shares of common stock to be repurchased by us. See "Use of Proceeds" and "Certain Relationships and Related Party Transactions."

(6)

Includes 100,000 shares of restricted stock, of which 50,000 are subject to vesting on February 24, 2006, and 128,720 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. Shares beneficially owned after this offering give effect to             shares of common stock to be repurchased by us. See "Use of Proceeds" and "Certain Relationships and Related Party Transactions."

(7)

Includes 50,000 shares of restricted stock, of which 37,500 remain subject to vesting in one-third increments on February 24, 2006, 2007 and 2008, and 89,560 shares issuable within 60 days upon the exercise of options granted under our 2003 Incentive Plan. Does not include 41,665 shares underlying options that are not exercisable within 60 days granted under our 2003 Incentive Plan. Shares beneficially owned after this offering give effect to             shares of common stock to be repurchased by us. See "Use of Proceeds" and "Certain Relationships and Related Party Transactions."

(8)

Includes 50,000 shares of restricted stock, of which 37,500 remain subject to vesting in one-third increments on February 24, 2006, 2007 and 2008, and 89,560 shares issuable within 60 days upon the exercise of options granted under our 2003 Incentive Plan. Does not include 51,665 shares underlying options that are not exercisable within 60 days granted under our 2003 Incentive Plan. Shares beneficially owned after this offering give effect to             shares of common stock to be repurchased by us. See "Use of Proceeds" and "Certain Relationships and Related Party Transactions."

(9)

Includes 8,335 shares issuable within 60 days upon the exercise of options granted under our 2003 Incentive Plan. Does not include 26,665 shares underlying options that are not exercisable within 60 days granted under our 2003 Incentive Plan.

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(10)

Includes 52,500 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.

(11)

Includes 15,835 shares issuable within 60 days upon the exercise of options granted under our 2003 Incentive Plan. Does not include 56,665 shares underlying options that are not exercisable within 60 days granted under our 2003 Incentive Plan.

(12)

Includes 17,500 shares issuable within 60 days upon the exercise of options granted under our 2003 Incentive Plan. Does not include 60,000 shares underlying options that are not exercisable within 60 days granted under our 2003 Incentive Plan.

(13)

Includes 52,500 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. Also reflects the beneficial ownership of an aggregate of 2,965,930 shares beneficially owned by Fortress Holdings, LLC and Anchor Resources, LLC. H. H. Wommack, III is a significant unitholder of Fortress Capital, 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.

(14)

Includes an aggregate of 837,500 restricted shares, of which 603,125 remain subject to vesting, and an aggregate of 959,265 shares issuable within 60 days upon the exercise of options granted under our 2003 Incentive Plan. Does not include 613,310 shares underlying options that are not exercisable within 60 days granted under our 2003 Incentive Plan.

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SELLING STOCKHOLDERS

        The following table and related footnotes set forth certain information regarding the selling stockholders. The number of shares in the column "Number of Shares Offered" represents all of the shares that each selling stockholder may offer under this prospectus assuming no exercise of the underwriters' over-allotment option. Except as noted below in the footnotes, the selling stockholders will each sell a pro rata number of the total shares that may be sold pursuant to the underwriters' over-allotment option. To our knowledge, each of the selling stockholders has sole voting and investment power as to the shares shown, except as disclosed in this prospectus or to the extent this power may be shared with a spouse. 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 selling stockholders is a director, officer or employee of ours or an affiliate of such person.

	Beneficial Ownership Prior to this Offering					Beneficial Ownership After this Offering
Selling Stockholders	Number of Shares	Percent of Class		Number of Shares Offered		Number of Shares	Percent of Class
DLJ Merchant Banking Partners III, L.P.(1)	17,852,420	(1	)	4,172,969		13,679,451	(1	)
DLJ ESC II, L.P.(1)	2,107,250	(1	)	492,566		1,614,684	(1	)
DLJ Offshore Partners III, C.V.(1)	629,225	(1	)	147,080		482,145	(1	)
DLJ Offshore Partners III-1, C.V.(1)	45,185	(1	)	10,562		34,623	(1	)
DLJ Offshore Partners III-2, C.V.(1)	32,185	(1	)	7,523		24,662	(1	)
DLJ Merchant Banking III, Inc., as Advisory General Partner on behalf of DLJ Offshore Partners III, C.V.(1)	619,065	(1	)	144,705		474,360	(1	)
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.(1)	276,980	(1	)	64,744		212,236	(1	)
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.(1)	197,315	(1	)	46,122		151,193	(1	)
DLJMB Partners III GmbH & Co. KG(1)	152,270	(1	)	35,593		116,677	(1	)
DLJMB Funding III, Inc.(1)	186,595	(1	)	43,616		142,979	(1	)
Millennium Partners II, L.P.(1)	30,365	(1	)	7,098		23,267	(1	)
MBP III Plan Investors, L.P.(1)	3,357,425	(1	)	784,792		2,572,633	(1	)
First Reserve Fund VIII, L.P.(2)(5)	3,371,175	11.7	%	788,006		2,583,169		%
Fortress Holdings, LLC(3)	941,590	3.3	%	220,095		721,495		%
Southwest Partners II, L.P.(3)	673,680	(3	)	157,471		516,209	(3	)
Southwest Partners III, L.P.(3)	1,350,660	(3	)	315,714		1,034,946	(3	)
Kenneth V. Huseman(4)	1,123,950	3.8	%	(4	)			%
Jay D. Hacklin(5)	14,810	*		3,462		11,348	*
William L. Hubbell Living Revocable Trust(5)	44,885	*		10,027		34,858	*
Jay R. Anderson(5)	10,780	*		2,520		8,260	*
Michael D. Schmid(5)	169,750	*		39,679		130,071	*
Peter O. Kane(5)	1,795	*		420		1,375	*
Randy Spaur(5)	9,875	*		2,308		7,567	*
Joey D. Fields	12,525	*		2,928		9,597	*

        We and all of the selling stockholders are parties to a Second Amended and Restated Stockholders' Agreement pursuant to which we have granted to such stockholders rights to register their shares of common stock.

*

Less than one percent.

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(1)

See footnote (1) under the table for "Principal Stockholders" and related beneficial ownership disclosure in table. These stockholders will not be exercising any warrants in connection with this offering.

(2)

See footnote (2) under the table for "Principal Stockholders" and related beneficial ownership disclosure in table.

(3)

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

(4)

See footnote (5) under the table for "Principal Stockholders" and related beneficial ownership disclosure in table. Mr Huseman will offer to sell up to 25,000 shares only as part of the underwriters' over-allotment option.

(5)

Former shareholder of FESCO Holdings Inc. See "Certain Relationships and Related Party Transactions — Summary of Certain Equity Issuances."

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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.

        Upon the completion of this offering             shares of common stock and no shares of preferred stock will be 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.

Escrow Agreement

        In September 2003, we acquired all the outstanding shares of FESCO Holdings Inc. in exchange for 3,650,000 shares of our common stock. In connection with this transaction, we entered into an escrow agreement pursuant to which 365,000 shares of the total consideration remain in escrow with the escrow agent to secure certain indemnification obligations of the sellers under the stock purchase agreement for this transaction. If we incur or suffer any losses for which the sellers are required to indemnify us, then we will be entitled to the number of shares in escrow equaling the dollar value of the loss. The sellers are the record owners of the shares in escrow and are entitled to exercise all voting rights with respect to such shares. Each seller's remaining shares in escrow will be released to such seller within twenty-five days after December 31, 2005.

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,

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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."

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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

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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, Southwest Royalties Holdings, Inc., Southwest Partners II, L.P. and Southwest Partners III, L.P., which we call the "Southwest Parties," and First Reserve Fund VIII, LP, Randy D. Spaur, Peter O. Kane, Michael D. Schmid, Jay R. Anderson, William L. Hubbell, Donald C. Busha Revocable Trust, and Jay D. Hacklin, which we call the "FESCO Parties," also have demand rights to require us to register shares of our common stock. The Southwest Parties and the FESCO Parties may each make one request to us to register shares of our common stock after the completion of an initial public offering, 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 current stockholders 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 will 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.

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 have been approved for listing on the NYSE under the symbol "BAS" subject to official notice of issuance.

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SHARES ELIGIBLE FOR FUTURE SALE

        Prior to this offering, there has been no public market for our common stock. The market price of our common stock could drop due to sales of a large number of shares of our common stock or the perception that these sales could occur. These factors also could make it more difficult to raise funds through future offerings of common stock.

        After this offering,             shares of common stock will be outstanding, or             shares if the underwriters exercise their over-allotment option in full. Of these shares, the             shares sold in this offering, or             shares if the underwriters exercise their over-allotment option in full, 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. A total of             shares will be "restricted securities" within the meaning of Rule 144 under the Securities Act or subject to lock-up arrangements. An aggregate of             of these shares will become available for resale in the public market as shown in the chart below:

Number of shares	Date of eligibility for resale into public market
	No less than 180 days after the date of this prospectus (in accordance with lock-up agreements with Goldman, Sachs & Co. and Credit Suisse First Boston LLC).
	Between 181 and 365 days after the date of this prospectus due to the requirements of the federal securities laws.

        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 offering, the holders of             shares of our common stock 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 officers and directors and all of our stockholders will enter into lock-up agreements described in "Underwriting."

        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.

        As soon as practicable after this offering, we intend to file one or more registration statements 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 these registration statements 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

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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.

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CERTAIN UNITED STATES FEDERAL TAX CONSIDERATIONS
FOR NON-UNITED STATES HOLDERS

        The following is a general discussion of the principal United States federal income and estate tax consequences of the ownership and disposition of our common stock that may be relevant to you if you are a non-U.S. holder. As used in this discussion, the term "non-U.S. holder" means a beneficial owner of our common stock that is not, for U.S. federal income tax purposes:

•

an individual who is a citizen or resident of the United States;



•

a corporation or partnership (including any entity treated as a corporation or partnership for U.S. federal income tax purposes) created or organized in or under the laws of the United States, or of any political subdivision of the United States;



•

an estate whose income is subject to U.S. federal income taxation regardless of its source; or



•

a trust, in general, if a U.S. court is able to exercise primary supervision over the administration of the trust and one or more U.S. persons have authority to control all substantial decisions of the trust, or if it has a valid election in effect under applicable U.S. Treasury Regulations to be treated as a United States person.

        An individual may be treated as a resident of the United States in any calendar year for U.S. federal income tax purposes, instead of a nonresident, by, among other ways, being present in the United States for at least 31 days in that calendar year and for an aggregate of at least 183 days during a three-year period ending in the current calendar year. For purposes of this calculation, you would count all of the days present in the current year, one-third of the days present in the immediately preceding year and one-sixth of the days present in the second preceding year. Residents are taxed for U.S. federal income tax purposes as if they were U.S. citizens.

        This discussion does not consider:

•

U.S. state or local or non-U.S. tax consequences;



•

all aspects of U.S. federal income and estate taxes or specific facts and circumstances that may be relevant to a particular non-U.S. holder's tax position, including the fact that in the case of a non-U.S. holder that is an entity treated as a partnership for U.S. federal income tax purposes, the U.S. tax consequences of holding and disposing of our common stock may be affected by certain determinations made at the partner level;



•

the tax consequences for the stockholders, partners or beneficiaries of a non-U.S. holder;



•

special tax rules that may apply to particular non-U.S. holders, such as financial institutions, insurance companies, tax-exempt organizations, U.S. expatriates, broker-dealers, and traders in securities; or



•

special tax rules that may apply to a non-U.S. holder that holds our common stock as part of a "straddle," "hedge," "conversion transaction," "synthetic security" or other integrated investment.

        The following discussion is based on provisions of the U.S. Internal Revenue Code of 1986, as amended, existing and proposed Treasury regulations and administrative and judicial interpretations, all as of the date of this prospectus, and all of which are subject to change, retroactively or prospectively. The following summary assumes that a non-U.S. holder holds our common stock as a capital asset. Each non-U.S. holder is urged to consult a tax advisor regarding the U.S. Federal, state, local and non-U.S. income and other tax consequences of acquiring, holding and disposing of shares of our common stock.

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Distributions on Common Stock

        In the event that we make cash distributions on our common stock, these distributions generally will constitute dividends for U.S. federal income tax purposes to the extent paid from our current or accumulated earnings and profits, as determined under U.S. federal income tax principles. Dividends paid to non-U.S. holders of our common stock that are not effectively connected with the non-U.S. holder's conduct of a U.S. trade or business will be subject to U.S. withholding tax at a 30% rate, or if a tax treaty applies, a lower rate specified by the treaty. Non-U.S. holders are urged to consult their tax advisors regarding their entitlement to benefits under a relevant income tax treaty.

        Dividends that are effectively connected with a non-U.S. holder's conduct of a trade or business in the United States and, if an income tax treaty applies, are attributable to a permanent establishment in the United States, are taxed on a net income basis at the regular graduated rates and in the manner applicable to U.S. persons. In that case, we will not have to withhold U.S. federal withholding tax if the non-U.S. holder complies with applicable certification and disclosure requirements. In addition, a "branch profits tax" may be imposed at a 30% rate, or a lower rate under an applicable income tax treaty, on dividends received by a foreign corporation that are effectively connected with the conduct of a trade or business in the United States.

        A non-U.S. holder that claims the benefit of an applicable income tax treaty generally will be required to satisfy applicable certification and other requirements. However,

•

in the case of common stock held by a foreign partnership, the certification requirement will generally be applied to the partners of the partnership and the partnership will be required to provide certain information;



•

in the case of common stock held by a foreign trust, the certification requirement will generally be applied to the trust or the beneficial owners of the trust depending on whether the trust is a "foreign complex trust," "foreign simple trust" or "foreign grantor trust" as defined in the U.S. Treasury regulations; and



•

look-through rules will apply for tiered partnerships, foreign simple trusts and foreign grantor trusts.

        A non-U.S. holder that is a foreign partnership or a foreign trust is urged to consult its own tax advisor regarding its status under these U.S. Treasury regulations and the certification requirements applicable to it.

        A non-U.S. holder that is eligible for a reduced rate of U.S. federal withholding tax under an income tax treaty may obtain a refund or credit of any excess amounts withheld by filing an appropriate claim for a refund with the U.S. Internal Revenue Service.

Gain on Disposition of Common Stock

        A non-U.S. holder generally will not be subject to U.S. federal income tax on gain recognized on a disposition of our common stock unless:

•

the gain is effectively connected with the non-U.S. holder's conduct of a trade or business in the United States and, if an income tax treaty applies, is attributable to a permanent establishment maintained by the non-U.S. holder in the United States; in these cases, the gain will be taxed on a net income basis at the regular graduated rates and in the manner applicable to U.S. persons and, if the non-U.S. holder is a foreign corporation, the "branch profits tax" described above may also apply;

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•

the non-U.S. holder is an individual who is present in the United States for 183 days or more in the taxable year of the disposition and meets other requirements; or



•

we are or have been a "United States real property holding corporation" for U.S. federal income tax purposes at any time during the shorter of the five-year period ending on the date of disposition or the period that the non-U.S. holder held our common stock.

        Generally, a corporation is a "United States real property holding corporation" if the fair market value of its "United States real property interests" equals or exceeds 50% of the sum of the fair market value of its worldwide real property interests plus its other assets used or held for use in a trade or business. The tax relating to stock in a "United States real property holding corporation" generally will not apply to a non-U.S. holder whose holdings, direct and indirect, at all times during the applicable period, constituted 5% or less of our common stock, provided that our common stock was regularly traded on an established securities market. We believe that we are not currently, and we do not anticipate becoming in the future, a "United States real property holding corporation" for U.S. federal income tax purposes.

U.S. Federal Estate Tax

        Common stock owned or treated as owned by an individual who is a non-U.S. holder for U.S. federal tax purposes at the time of death will be included in the individual's gross estate for U.S. federal estate tax purposes, unless an applicable estate tax or other treaty provides otherwise and, therefore, may be subject to U.S. federal estate tax.

Information Reporting and Backup Withholding Tax

        Dividends paid to you may be subject to information reporting and U.S. backup withholding. If you are a non-U.S. holder you will be exempt from this backup withholding tax if you properly provide a Form W-8BEN certifying that you are a non-U.S. holder or you otherwise meet documentary evidence requirements for establishing that you are a non-U.S. holder or otherwise establish an exemption.

        The gross proceeds from the disposition of our common stock may be subject to information reporting and backup withholding. If you sell your common stock outside the United States through a non-U.S. office of a non-U.S. broker and the sales proceeds are paid to you outside the United States, then the U.S. backup withholding and information reporting requirements generally will not apply to that payment. However, U.S. information reporting, but not backup withholding, will generally apply to a payment of sales proceeds, even if that payment is made outside the United States, if you sell your common stock through a non-U.S. office of a broker that:

•

is a United States person;



•

derives 50% or more of its gross income in specific periods from the conduct of a trade or business in the United States;



•

is a "controlled foreign corporation" for U.S. tax purposes; or



•

is a foreign partnership, if at any time during its tax year:

•

one or more of its partners are United States persons who in the aggregate hold more than 50% of the income or capital interests in the partnership; or

•

the foreign partnership is engaged in a U.S. trade or business,

unless the broker has documentary evidence in its files that you are a non-U.S. person and certain other conditions are met or you otherwise establish an exemption.

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        If you receive payments of the proceeds of a sale of our common stock to or through a U.S. office of a broker, the payment is subject to both U.S. backup withholding and information reporting unless you properly provide a Form W-8BEN certifying that you are a non-U.S. person or you otherwise establish an exemption.

        You generally may obtain a refund of any amounts withheld under the backup withholding rules that exceed your U.S. federal income tax liability by timely filing a properly completed refund claim with the U.S. Internal Revenue Service.

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UNDERWRITING

        We, the selling stockholders and the underwriters named below have entered into an underwriting agreement with respect to the shares being offered. Subject to certain conditions, each underwriter has severally agreed to purchase the number of shares indicated in the following table. Goldman, Sachs & Co. and Credit Suisse First Boston LLC are the representatives of the underwriters.

Underwriters		Number of Shares
Goldman, Sachs & Co.
Credit Suisse First Boston LLC
Lehman Brothers Inc.
UBS Securities LLC
Deutsche Bank Securities Inc.
Raymond James & Associates, Inc.
RBC Capital Markets Corporation
	Total	12,500,000

        The underwriters are committed to take and pay for all of the shares being offered, if any are taken, other than the shares covered by the option described below unless and until this option is exercised.

        If the underwriters sell more shares than the total number set forth in the table above, the underwriters have an option to buy up to an additional 1,875,000 shares from the selling stockholders to cover such sales. They may exercise that option for 30 days. If any shares are purchased pursuant to this option, the underwriters will severally purchase shares in approximately the same proportion as set forth in the table above.

        The following tables show the per share and total underwriting discounts and commissions to be paid to the underwriters by us and the selling stockholders. Such amounts are shown assuming both no exercise and full exercise of the underwriters' option to purchase             additional shares.

Paid by Us	No Exercise	Full Exercise
Per Share	$	$
Total	$	$

Paid by the Selling Stockholders	No Exercise	Full Exercise
Per Share	$	$
Total	$	$

        Shares sold by the underwriters to the public will initially be offered at the initial public offering price set forth on the cover of this prospectus. Any shares sold by the underwriters to securities dealers may be sold at a discount of up to $             per share from the initial public offering price. Any such securities dealers may resell any shares purchased from the underwriters to certain other brokers or dealers at a discount of up to $             per share from the initial public offering price. If all the shares are not sold at the initial public offering price, the representatives may change the offering price and the other selling terms.

        We and our executive officers, directors, and holders of all of our outstanding shares of common stock, including the selling stockholders, have agreed with the underwriters, other than in this offering and subject to certain exceptions, not to dispose of or hedge any shares of our common stock or securities convertible into, or exercisable or exchangeable for, shares of common

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stock during the period from the date of this prospectus continuing through the date 180 days after the date of this prospectus, except with the prior written consent of the representatives. This agreement does not apply to the issuance by us of any securities in accordance with any of our existing employee benefit plans. See "Shares Available for Future Sale" for a discussion of certain transfer restrictions.

        The 180-day restricted period described in the preceding paragraph will be automatically extended if: (1) during the last 17 days of the 180-day restricted period we issue an earnings release or announce material news or a material event; or (2) prior to the expiration of the 180-day restricted period, we announce that we will release earnings results during the 15-day period following the last day of the 180-day period, in which case the restrictions described in the preceding paragraph will continue to apply until the expiration of the 18-day period beginning on the issuance of the earnings release of the announcement of the material news or material event.

        Prior to the offering, there has been no public market for the shares. The initial public offering price will be negotiated among us, the selling stockholders and the representatives. The factors to be considered in determining the initial public offering price of the shares will be prevailing market conditions, our historical performance, estimates of our business potential and earnings prospects, an assessment of our management and the consideration of the above factors in relation to market valuation of companies in related businesses.

        The common stock has been approved for listing on the New York Stock Exchange under the symbol "BAS" subject to official notice of issuance. In order to meet one of the requirements for listing the common stock on the NYSE, the underwriters have undertaken to sell lots of 100 or more shares to a minimum of 2,000 beneficial holders.

        In connection with the offering, the underwriters may purchase and sell shares of common stock in the open market. These transactions may include short sales, stabilizing transactions and purchases to cover positions created by short sales. Shorts sales involve the sale by the underwriters of a greater number of shares than they are required to purchase in the offering. "Covered" short sales are sales made in an amount not greater than the underwriters' option to purchase additional shares from the selling stockholders in the offering. The underwriters may close out any covered short position by either exercising their option to purchase additional shares or purchasing shares in the open market. In determining the source of shares to close out the covered short position, the underwriters will consider, among other things, the price of shares available for purchase in the open market as compared to the price at which they may purchase additional shares pursuant to the option granted to them. "Naked" short sales are any sales in excess of such option. The underwriters must close out any naked short position by purchasing shares in the open market. A naked short position is more likely to be created if the underwriters are concerned that there may be downward pressure on the price of the common stock in the open market after pricing that could adversely affect investors who purchase in the offering. Stabilizing transactions consist of various bids for or purchases of common stock made by the underwriters in the open market prior to the completion of the offering.

        The underwriters may also impose a penalty bid. This occurs when a particular underwriter repays to the underwriters a portion of the underwriting discount received by it because the representatives have repurchased shares sold by or for the account of such underwriter in stabilizing or short covering transactions.

        Purchases to cover a short position and stabilizing transactions may have the effect of preventing or retarding a decline in the market price of our common stock, and together with the imposition of the penalty bid, may stabilize, maintain or otherwise affect the market price of the common stock. As a result, the price of the common stock may be higher than the price that otherwise might exist in the open market. If these activities are commenced, they may be

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discontinued at any time. These transactions may be effected on the New York Stock Exchange, in the over-the-counter market or otherwise.

        Each of the underwriters has represented and agreed that:

•

it has not made and will not make an offer of shares to the public in the United Kingdom within the meaning of section 102B of the Financial Services and Markets Act 2000 (as amended) ("FSMA") except to legal entities which are authorized or regulated to operate in the financial markets or, if not so authorized or regulated, whose corporate purpose is solely to invest in securities or otherwise in circumstances which do not require the publication by us of a prospectus pursuant to the Prospectus Rules of the Financial Services Authority ("FSA");



•

it has only communicated or caused to be communicated and will only communicate or cause to be communicated an invitation or inducement to engage in investment activity (within the meaning of section 21 of FSMA) to persons who have professional experience in matters relating to investments falling within Article 19(5) of the Financial Services and Markets Act 2000 (Financial Promotion) Order 2005 or in circumstances in which section 21 of FSMA does not apply to us; and



•

it has complied with and will comply with all applicable provisions of FSMA with respect to anything done by it in relation to the shares in, from or otherwise involving the United Kingdom.

        In relation to each Member State of the European Economic Area which has implemented the Prospectus Directive (each, a "Relevant Member State"), each underwriter has represented and agreed that with effect from and including the date on which the Prospectus Directive is implemented in that Relevant Member State (the "Relevant Implementation Date") it has not made and will not make an offer of shares to the public in that Relevant Member State prior to the publication of a prospectus in relation to the shares which has been approved by the competent authority in that Relevant Member State or, where appropriate, approved in another Relevant Member State and notified to the competent authority in that Relevant Member State, all in accordance with the Prospectus Directive, except that it may, with effect from and including the Relevant Implementation Date, make an offer of shares to the public in that Relevant Member State at any time:

•

to legal entities which are authorized or regulated to operate in the financial markets or, if not so authorized or regulated, whose corporate purpose is solely to invest in securities;



•

to any legal entity which has two or more of (1) an average of at least 250 employees during the last financial year; (2) a total balance sheet of more than €43,000,000 and (3) an annual net turnover of more than €50,000,000, as shown in its last annual or consolidated accounts; or



•

in any other circumstances which do not require the publication by us of a prospectus pursuant to Article 3 of the Prospectus Directive.

        For purposes of this provision, the expression an "offer of shares to the public" in relation to any shares in any Relevant Member State means the communication in any form and by any means of sufficient information on the terms of the offer and the shares to be offered so as to enable an investor to decide to purchase or subscribe for the Shares, as the same may be varied in that Member State by any measure implementing the Prospectus Directive in that Member State, and the expression "Prospectus Directive" means Directive 2003/71/EC and includes any relevant implementing measure in each Relevant Member State.

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        The shares may not be offered or sold by means of any document other than to persons whose ordinary business is to buy or sell shares or debentures, whether as principal or agent, or in circumstances which do not constitute an offer to the public within the meaning of the Companies Ordinance (Cap. 32) of Hong Kong, and no advertisement, invitation or document relating to the shares may be issued, whether in Hong Kong or elsewhere, which is directed at, or the contents of which are likely to be accessed or read by, the public in Hong Kong (except if permitted to do so under the securities laws of Hong Kong) other than with respect to shares which are or are intended to be disposed of only to persons outside Hong Kong or only to "professional investors" within the meaning of the Securities and Futures Ordinance (Cap. 571) of Hong Kong and any rules made thereunder.

        This prospectus has not been registered as a prospectus with the Monetary Authority of Singapore. Accordingly, this prospectus and any other document or material in connection with the offer or sale, or invitation for subscription or purchase, of the shares may not be circulated or distributed, nor may the shares be offered or sold, or be made the subject of an invitation for subscription or purchase, whether directly or indirectly, to persons in Singapore other than (i) to an institutional investor under Section 274 of the Securities and Futures Act, Chapter 289 of Singapore (the "SFA"), (ii) to a relevant person, or any person pursuant to Section 275(1A), and in accordance with the conditions, specified in Section 275 of the SFA or (iii) otherwise pursuant to, and in accordance with the conditions of, any other applicable provision of the SFA.

        Where the shares are subscribed or purchased under Section 275 by a relevant person which is (a) a corporation (which is not an accredited investor) the sole business of which is to hold investments and the entire share capital of which is owned by one or more individuals, each of whom is an accredited investor or (b) a trust (where the trustee is not an accredited investor) whose sole purpose is to hold investments and each beneficiary is an accredited investor, shares, debentures and units of shares and debentures of that corporation or the beneficiaries' rights and interest in that trust shall not be transferable for six months after that corporation or that trust has acquired the shares under Section 275 except (i) to an institutional investor under Section 274 of the SFA or to a relevant person, or any person pursuant to Section 275(1A), and in accordance with the conditions, specified in Section 275 of the SFA, (ii) where no consideration is given for the transfer or (iii) by operation of law.

        The securities have not been and will not be registered under the Securities and Exchange Law of Japan (the "Securities and Exchange Law"), and each underwriter has agreed that it will not offer or sell any securities, directly or indirectly, in Japan or to, or for the benefit of, any resident of Japan (which term as used herein means any person resident in Japan, including any corporation or other entity organized under the laws of Japan), or to others for re-offering or resale, directly or indirectly, in Japan or to a resident of Japan, except pursuant to an exemption from the registration requirements of, and otherwise in compliance with, the Securities and Exchange Law and any other applicable laws, regulations and ministerial guidelines of Japan.

        If you purchase shares of common stock offered in this prospectus, you may be required to pay stamp taxes and other charges under the laws and practices of the country of purchase, in addition to the offering price listed on the cover page of this prospectus.

        Credit Suisse First Boston LLC, one of the underwriters, is considered to be our affiliate due to the significant ownership of our outstanding common stock by DLJ Merchant Banking which is comprised of funds that are affiliates of Credit Suisse First Boston LLC. DLJ Merchant Banking is a selling stockholder in this offering. Please read "Selling Stockholders." Because Credit Suisse First Boston LLC is our affiliate, the underwriters may be deemed to have a "conflict of interest" under Rule 2710(c)(8) of the Conduct Rules of the National Association of Securities Dealers, Inc. Accordingly, this offering will be made in compliance with the applicable provisions of Rule 2720 of

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the Conduct Rules. Rule 2720 requires that the initial public offering price can be no higher than that recommended by a "qualified independent underwriter," as defined by the NASD. Accordingly, Goldman, Sachs & Co., another underwriter of this offering, is assuming the responsibilities of acting as the qualified independent underwriter in pricing this offering, conducting due diligence and reviewing and participating in the preparation of this prospectus and the registration statement of which this prospectus forms a part. The initial public offering price of the shares of common stock will be no higher than the price recommended by Goldman, Sachs & Co. We will pay Goldman, Sachs & Co. a fee of $10,000 for acting as the qualified independent underwriter.

        At our request, the underwriters have reserved for sale at the initial public offering price up to 625,000 shares of the common stock for employees, directors and other persons associated with us who have expressed an interest in purchasing common stock in the offering. The number of shares available for sale to the general public offering will be reduced to the extent these persons purchase the reserved shares. Any reserved shares not so purchased will be offered by the underwriters to the general public on the same terms as the other shares. We have agreed to indemnify the underwriters against certain liabilities and expenses, including liabilities under the Securities Act, in connection with the reserved share program.

        The underwriters have informed us that they will not confirm sales to accounts over which they exercise discretionary authority without the prior written approval of the customer.

        We will pay all of the expenses of the offering, including those of the selling stockholders (other than underwriting discounts and commissions relating to the shares sold by the selling stockholders). We estimate that the total expenses of the offering will be approximately $1.7 million.

        A prospectus in electronic format will be made available on the web sites maintained by one or more of the underwriters or selling group members, if any, participating in this offering and one or more of the underwriters participating in this offering may distribute prospectuses electronically. The representatives may agree to allocate a number of shares to underwriters and selling group members for sale to their online brokerage account holders. Internet distributions will be allocated by the representatives to underwriters that may make Internet distributions on the same basis as other allocations.

        We and the selling stockholders have agreed to indemnify the several underwriters, and Goldman, Sachs & Co. in its capacity as qualified independent underwriter, against certain liabilities, including liabilities under the Securities Act.

        Certain of the underwriters and their respective affiliates have performed for us the financial advisory, commercial banking and investment banking services specified below, for which they received customary fees and expenses. In addition, certain of the underwriters and their respective affiliates may in the future perform additional financial advisory, commercial banking or investment banking services for us, for which they will receive customary fees and expenses.

        Affiliates of UBS Securities LLC are arrangers, agents and lenders under our 2004 Credit Facility and receive fees customary for performing these services and interest on such indebtedness. See "Management's Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources." Affiliates of Credit Suisse First Boston LLC, Deutsche Bank Securities Inc., UBS Securities LLC and RBC Capital Markets Corporation are lenders under the revolving loans under our credit facility.

        We completed a private recapitalization in December 2000 by DLJ Merchant Banking, which gained majority control of us. DLJ Merchant Banking has invested approximately $81 million through staged equity injections and has been instrumental in providing capital to support our recent growth. DLJ Merchant Banking currently owns approximately 73.1% of our shares of common stock. DLJ Merchant Banking is selling shares of our common stock in this offering. See

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"Selling Stockholders." Following the consummation of this offering, DLJ Merchant Banking, which is comprised of funds that are affiliates of Credit Suisse First Boston LLC, will own     % of our common stock (    % if the underwriters' over-allotment option is exercised in full).

        Pursuant to the terms of our stockholders' agreement among us, DLJ Merchant Banking and our other stockholders, DLJ Merchant Banking had the right to designate a majority of the members of our Board of Directors. After the completion of this offering, DLJ Merchant Banking will continue to have representatives that compose a majority of our Board of Directors but will no longer have the right to designate members of our Board of Directors.

        Subject to certain restrictions, the stockholders' agreement also provides DLJ Merchant Banking 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 this 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). We have agreed to pay most offering fees and expenses associated with the registration and offering of these shares, other than underwriting fees, discounts or commissions. We have also agreed to indemnify these stockholders and their officers, directors, partners, legal counsel and other listed representatives against certain losses, claims, damages or liabilities in connection with the registered offering of their shares. See "Certain Relationships and Related Transactions."

        Following the completion of this offering, Credit Suisse First Boston LLC will be considered to be our affiliate due to the ownership by its affiliates of a significant percentage of the outstanding shares of our common stock. Because of this affiliate status, the rules of the New York Stock Exchange will prohibit Credit Suisse First Boston LLC from soliciting, or making recommendations regarding, the purchase or sale of our common stock following the completion of this offering, until such time as Credit Suisse First Boston LLC ceases to be our affiliate. These rules may effectively preclude Credit Suisse First Boston LLC from preparing and disseminating analysts' research reports and earnings estimates related to us until it ceases to be our affiliate.

LEGAL MATTERS

        The validity of the shares of common stock offered by this prospectus will be passed upon for us by Andrews Kurth LLP, Houston, Texas and passed upon for the underwriters by Vinson & Elkins L.L.P., Houston, Texas.

EXPERTS

        The consolidated financial statements of Basic Energy Services, Inc. and subsidiaries as of December 31, 2003 and 2004, and for each of the years in the three-year period ended December 31, 2004, have been included in this prospectus and in the registration statement in reliance upon the report of KPMG LLP, independent registered public accountants, 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, 2004 consolidated financial statements refers to a change in the method of accounting for asset retirement obligations as of January 1, 2003, and a change in the method of accounting for goodwill and other intangible assets as of January 1, 2002. The audit report covering the December 31, 2004 consolidated financial statements also refers to a restatement of the consolidated statements of operations, stockholders' equity, and cash flows for each of the years in the two-year period ended December 31, 2003.

        The audited consolidated financial statements of FESCO Holdings, Inc. and its subsidiaries as of December 31, 2002 and for the year then ended included in this prospectus have been so included in reliance on the report of PricewaterhouseCoopers LLP, independent accountants, given on the authority of said firm as experts in auditing and accounting.

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        The consolidated financial statements of First Energy Services Company and its subsidiaries as of and for the year ended December 31, 2001 and as of and for the period from inception (April 19, 2000) to December 31, 2000 included in this prospectus have been audited by Arthur Andersen LLP, independent public accountants, as indicated in their reports with respect thereto, and have been so included in reliance upon the authority of said firm as experts in giving said reports. Subsequent to Arthur Andersen LLP's completion of the 2001 audit of First Energy Services Company and its subsidiaries, the firm was convicted of obstruction of justice charges relating to a federal investigation of Enron Corporation, has ceased practicing before the SEC, and has lost the services of the material personnel responsible for said audit. As a result, it is not possible to obtain Arthur Andersen LLP's consent to the inclusion of their report in this prospectus, and we have dispensed with the requirement to file their consent in reliance upon Rule 437a of the Securities Act of 1933. Because Arthur Andersen LLP has not consented to the inclusion of their report in this prospectus, you will not be able to recover against Arthur Andersen LLP under Section 11 of the Securities Act for any untrue statements of a material fact contained in the consolidated financial statements audited by Arthur Andersen LLP or any omissions to state a material fact required to be stated therein.

        The combined financial statements of the business acquired from PWI Inc. for the nine months ended September 30, 2003 have been included in this prospectus and registration statement upon the report of KPMG LLP, independent registered public accountants, appearing elsewhere in this prospectus, and upon the authority of said firm as experts in accounting and auditing. The audit report covering the September 30, 2003 financial statements refers to a change in the method of accounting for asset retirement obligations as of January 1, 2003.

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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.

        Following the completion of this offering, we will 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 expect to 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.

        We intend to furnish or make available to our stockholders annual reports containing our audited financial statements prepared in accordance with GAAP. We also intend to furnish or make available to our stockholders quarterly reports containing our unaudited interim financial information, including the information required by Form 10-Q, for the first three fiscal quarters of each fiscal year.

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INDEX TO FINANCIAL STATEMENTS

Basic Energy Services, Inc.
Audited Consolidated Financial Statements
	Report of Independent Registered Public Accounting Firm
	Consolidated Balance Sheets at December 31, 2004 and 2003
	Consolidated Statements of Operations and Comprehensive Income (Loss) for the years ended December 31, 2004, 2003 and 2002
	Consolidated Statements of Stockholders' Equity for the years ended December 31, 2004, 2003 and 2002
	Consolidated Statements of Cash Flows for the years ended December 31, 2004, 2003 and 2002
	Notes to Consolidated Financial Statements
Unaudited Consolidated Financial Statements
	Consolidated Balance Sheets as of June 30, 2005 and December 31, 2004
	Consolidated Statements of Operations and Comprehensive Income for the six months ended June 30, 2005 and 2004
	Consolidated Statements of Stockholders' Equity for the six months ended June 30, 2005
	Consolidated Statements of Cash Flows for the six months ended June 30, 2005 and 2004
	Notes to Consolidated Financial Statements
FESCO Holdings, Inc. and Subsidiaries
Audited Consolidated Financial Statements
	Report of Independent Auditors
	Consolidated Balance Sheet as of December 31, 2002
	Consolidated Statements of Operations for the year ended December 31, 2002
	Consolidated Statements of Stockholders' Equity for the year ended December 31, 2002
	Consolidated Statements of Cash Flows for the year ended December 31, 2002
	Notes to Consolidated Financial Statements
Audited Consolidated Financial Statements
	Report of Independent Public Accountants
	Consolidated Balance Sheets as of December 31, 2001 and 2000
	Consolidated Statements of Income for the year ended December 31, 2001 and for the period from inception to December 31, 2000
	Consolidated Statements of Stockholders' Equity for the year ended December 31, 2001 and for the period from inception to December 31, 2000
	Consolidated Statements of Cash Flows for the year ended December 31, 2001 and for the period from inception to December 31, 2000
	Notes to Consolidated Financial Statements
Unaudited Consolidated Financial Statements
	Consolidated Balance Sheet at September 30, 2003
	Consolidated Statements of Operations for the nine months ended September 30, 2003
	Consolidated Statements of Stockholders' Equity for the nine months ended September 30, 2003
	Consolidated Statements of Cash Flows for the nine months ended September 30, 2003
	Notes to Consolidated Financial Statements

F-1

PWI Inc.
Audited Combined Financial Statements
	Report of Independent Registered Public Accounting Firm
	Statements of Combined Operations for the nine months ended September 30, 2003
	Statements of Combined Equity for the nine months ended September 30, 2003
	Statements of Combined Cash Flows for the nine months ended September 30, 2003
	Notes to Combined Financial Statements

F-2

Report of Independent Registered Public Accounting Firm

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

        We have audited the accompanying consolidated balance sheets of Basic Energy Services, Inc. and subsidiaries (the "Company") as of December 31, 2004 and 2003, 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, 2004. These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

        We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether 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, 2004 and 2003, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2004 in conformity with U.S. generally accepted accounting principles.

        As discussed in Note 2 to the consolidated financial statements, the Company changed its method of accounting for asset retirement obligations as of January 1, 2003 and the Company changed its method of accounting for goodwill and other intangible assets as of January 1, 2002.

        As discussed in Note 20 to the accompanying consolidated financial statements, the Company has restated the consolidated balance sheets as of December 31, 2004 and 2003 and the consolidated statements of operations, stockholders' equity, and cash flows for each of the years in the two-year period ended December 31, 2003.

KPMG LLP
Dallas, TX
June 13, 2005
except as to Note 19b, which is as of July 25, 2005,
Note 19c, which is as of September 22, 2005,
and Note 20, which is as of October 31, 2005.

F1-1

Basic Energy Services, Inc.

Consolidated Balance Sheets

(in thousands, except share data)

			December 31,
			2004			2003
			(as restated)			(as restated)
Assets
Current assets:
	Cash and cash equivalents		$	20,147		$	25,697
	Trade accounts receivable, net of allowance of $3,108 and $1,958, respectively			56,651			42,600
	Accounts receivable — related parties			103			151
	Income tax refund receivable			355			366
	Inventories			1,176			1,529
	Prepaid expenses			1,798			2,280
	Other current assets			2,099			1,264
	Deferred tax assets			4,899			3,642
		Total current assets		87,228			77,529
Property and equipment, net				233,451			188,243
Deferred debt costs, net of amortization				4,709			4,913
Goodwill				39,853			30,284
Other assets				2,360			1,684
			$	367,601		$	302,653
Liabilities and Stockholders' Equity
Current liabilities:
	Accounts payable		$	11,388		$	7,798
	Accrued expenses			20,486			19,750
	Current portion of long-term debt			11,561			6,393
	Other current liabilities			545			—
		Total current liabilities		43,980			33,941
Long-term debt				170,915			142,116
Deferred income				44			381
Deferred tax liabilities				30,247			18,267
Other long-term liabilities				629			653
Commitments and contingencies
Stockholders' equity:
	Common stock; $.01 par value; 80,000,000 shares authorized; 28,931,935 and 28,094,435 issued and outstanding at December 31, 2004 and December 31, 2003, respectively			58			56
	Additional paid-in capital			142,802			136,524
	Deferred compensation			(4,990	)		(297	)
	Accumulated deficit			(16,127	)		(28,988	)
	Accumulated other comprehensive income			43			—
		Total stockholders' equity		121,786			107,295
			$	367,601		$	302,653

See accompanying notes to consolidated financial statements.

F1-2

Basic Energy Services, Inc.

Consolidated Statements of Operations and Comprehensive Income (Loss)

(Dollars in thousands, except per share amounts)

			Years Ended December 31,
			2004			2003			2002
						(as restated)			(as restated)
Revenues:
	Well servicing		$	142,551		$	104,097		$	73,848
	Fluid services			98,683			52,810			34,170
	Well site construction services			40,927			9,184			—
	Drilling and completion services			29,341			14,808			733
		Total revenues		311,502			180,899			108,751
Expenses:
	Well servicing			98,058			73,244			55,643
	Fluid services			65,167			34,420			22,705
	Well site construction services			31,454			6,586			—
	Drilling and completion services			17,481			9,363			512
	General and administrative, including stock-based compensation of $1,587, $994 and $0 in 2004, 2003 and 2002, respectively			37,186			22,722			13,019
	Depreciation and amortization			28,676			18,213			13,414
	Loss (gain) on disposal of assets			2,616			391			351
		Total expenses		280,638			164,939			105,644
		Operating income		30,864			15,960			3,107
Other income (expense):
	Interest expense			(9,714	)		(5,234	)		(4,832	)
	Interest income			164			60			82
	Loss on early extinguishment of debt			—			(5,197	)		—
	Other income (expense)			(398	)		146			31
Income (loss) from continuing operations before income taxes				20,916			5,735			(1,612	)
Income tax (expense) benefit				(7,984	)		(2,772	)		382
Income (loss) from continuing operations				12,932			2,963			(1,230	)
Discontinued operations, net of tax				(71	)		22			—
Cumulative effect of accounting change, net of tax				—			(151	)		—
Net income (loss)				12,861			2,834			(1,230	)
Preferred stock dividend				—			(1,525	)		(1,075	)
Accretion of preferred stock discount				—			(3,424	)		(374	)
Net income (loss) available to common stockholders			$	12,861		$	(2,115	)	$	(2,679	)
Basic earnings per share of common stock:
	Continuing operations less preferred stock dividend and accretion		$	0.46		$	(0.09	)	$	(0.13	)
	Discontinued operations			—			—			—
	Cumulative effect of accounting change			—			—			—
	Net income (loss) available to common stockholders		$	0.46		$	(0.09	)	$	(0.13	)
Diluted earnings per share of common stock:
	Continuing operations less preferred stock dividend and accretion		$	0.42		$	(0.09	)	$	(0.13	)
	Discontinued operations			—			—			—
	Cumulative effect of accounting change			—			—			—
	Net income (loss) available to common stockholders		$	0.42		$	(0.09	)	$	(0.13	)
Comprehensive income (loss):
Net income (loss)			$	12,861		$	2,834		$	(1,230	)
Unrealized gains on hedging activities				43			—			—
Comprehensive income (loss):			$	12,904		$	2,834		$	(1,230	)

See accompanying notes to consolidated financial statements.

F1-3

Basic Energy Services, Inc.

Consolidated Statements of Stockholders' Equity

(in thousands, except share data)

	Common Stock												Accumulated Other Comprehensive Income
				Additional Paid-In Capital			Deferred Compensation			Accumulated Deficit					Total Stockholders' Equity
	Shares	Amount
Balance — December 31, 2001	17,368,610	$	35	$	81,685		$	—		$	(22,543	)	$	—	$	59,177
Adjustment	—		—		(684	)		—			445			—		(239	)
Balance — December 31, 2001 (as restated)	17,368,610		35		81,001			—			(22,098	)		—		58,938
Common stock issued	3,000,000		6		11,994			—			—			—		12,000
Preferred stock dividends	—		—		—			—			(1,075	)		—		(1,075	)
Preferred stock discount	—		—		4,299			—			—			—		4,299
Accretion of preferred stock discount	—		—		—			—			(374	)		—		(374	)
Net loss (restated)	—		—		—			—			(1,230	)		—		(1,230	)
Balance — December 31, 2002 (as restated)	20,368,610		41		97,294			—			(24,777	)		—		72,558
Exercise of EBITDA contingent warrants	771,740		2		—			—			—			—		2
EBITDA contingent warrants (restated)	—		—		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 (restated)	3,304,085		6		16,459			—			564			—		17,029
Accretion of preferred stock discount (restated)	—		—		—			—			(3,424	)		—		(3,424	)
Preferred stock dividends	—		—		—			—			(1,525	)		—		(1,525	)
Net income (restated)	—		—		—			—			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

See accompanying notes to consolidated financial statements.

F1-4

Basic Energy Services, Inc.

Consolidated Statements of Cash Flows

(in thousands)

				Years Ended December 31,
				2004			2003			2002
							(as restated)			(as restated)
Cash flows from operating activities:
	Net income (loss)			$	12,861		$	2,834		$	(1,230	)
	Adjustments to reconcile net income (loss) to net cash provided by operating activities:
		Depreciation and amortization			28,676			18,213			13,414
		Accretion on asset retirement obligation			33			28			—
		Change in allowance for doubtful accounts			1,150			1,279			200
		Non-cash interest expense			970			694			766
		Non-cash compensation			1,587			994			—
		Loss on early extinguishment of debt			—			3,588			—
		Loss on disposal of assets			2,616			391			351
		Deferred income taxes			7,984			2,840			1,536
		Other non-cash items			—			(11	)		382
		Non-cash effect of discontinued operations			—			13			—
		Cumulative effect of accounting change			—			151			—
	Changes in operating assets and liabilities, net of acquisitions:
		Accounts receivable			(13,841	)		(12,120	)		(2,776	)
		Inventories			394			125			62
		Income tax receivable			11			1,093			1,012
		Prepaid expenses and other current assets			435			(2,336	)		611
		Other assets			(569	)		1,261			—
		Accounts payable			3,416			2,863			1,289
		Income taxes payable			—			—			(181	)
		Deferred income and other liabilities			127			(11	)		(195	)
		Accrued expenses			689			7,926			1,771
			Net cash provided by operating activities		46,539			29,815			17,012
Cash flows from investing activities:
	Purchase of property and equipment				(55,674	)		(23,501	)		(14,674	)
	Proceeds from sale of assets				2,484			660			446
	Payments for other long-term assets				(1,113	)		(177	)		—
	Payments for businesses, net of cash acquired				(19,284	)		(61,885	)		(31,075	)
			Net cash used in investing activities		(73,587	)		(84,903	)		(45,303	)
Cash flows from financing activities:
	Proceeds from debt				43,500			203,012			1,900
	Payments of debt				(21,236	)		(115,603	)		(6,846	)
	Collections of notes receivable				—			9			32
	Proceeds from issuance of common stock				—			—			12,000
	Proceeds from issuance of preferred stock				—			—			14,942
	Proceeds from exercise of EBITDA contingent warrants				—			2			—
	Deferred loan costs and other financing activities				(766	)		(7,561	)		(456	)
			Net cash provided by financing activities		21,498			79,859			21,572
			Net increase (decrease) in cash and equivalents		(5,550	)		24,771			(6,719	)
Cash and cash equivalents — beginning of year					25,697			926			7,645
Cash and cash equivalents — end of year				$	20,147		$	25,697		$	926

See accompanying notes to consolidated financial statements.

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Basic Energy Services, Inc.

Notes To Consolidated Financial Statements

December 31, 2004, 2003 and 2002

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, well site construction services and drilling and completion 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 of the states of Texas, New Mexico, Oklahoma and Louisiana, and the Rocky Mountain region.

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. 46 or Accounting Research Bulletin No. 51. All inter-company transactions and balances have been eliminated.

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Estimates and Uncertainties

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

•

Depreciation and amortization of property and equipment and intangible assets



•

Impairment of property and equipment 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 obligations

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.

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.

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.

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Cash and Cash Equivalents

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

Fair Value of Financial Instruments

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

Inventories

        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 services 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
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.

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Impairments

        On January 1, 2002, Basic adopted Statement of Financial Accounting Standards No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets ("SFAS No. 144"). SFAS No. 144 provides a single accounting model for long-lived assets to be disposed of. SFAS No. 144 also changes the criteria for classifying an asset as held for sale; broadens the scope of businesses to be disposed of that qualify for reporting as discontinued operations; and changes the timing of recognizing losses on such operations. The adoption of SFAS No. 144 did not materially affect Basic's financial statements.

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

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

        Prior to the adoption of SFAS No. 144, Basic accounted for long-lived assets in accordance with SFAS No. 121, Accounting for Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of. Basic had no impairment expense in 2004, 2003 or 2002.

Deferred Debt Costs

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

        Deferred debt costs of approximately $5.8 million and $5.2 million at December 31, 2004 and 2003, respectively, represent debt issuance costs and are recorded net of accumulated amortization of $1.1 million, and $238,000 at December 31, 2004 and 2003, respectively. Amortization of deferred debt costs totaled approximately $907,000, $694,000, and $766,000 for the years ended December 31, 2004, 2003 and 2002, respectively. See note 5 regarding the losses on extinguishment of debt.

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Goodwill

        Basic adopted Statement of Financial Accounting Standards No. 142, Goodwill and Other Intangible Assets ("SFAS No. 142") on January 1, 2002. SFAS No. 142 eliminates the amortization for 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 subsequent annual impairment assessments as of December 31, 2004 and 2003. The assessments did not result in any indications of goodwill impairment.

        Intangible assets subject to amortization under SFAS No. 142 consist of non-compete agreements. Amortization expense for the non-compete agreements is calculated using the straight-line method over the period of the agreement, ranging from three to five years. The weighted average amortization period for non-compete agreements acquired during 2004 and 2003 is 60 months and 59 months, respectively.

        The gross carrying amount of non-compete agreements subject to amortization totaled approximately $3.7 million and $3.1 million at December 31, 2004 and 2003, respectively. Accumulated amortization related to these intangible assets totaled approximately $2.4 million and $1.9 million at December 31, 2004 and 2003, respectively. Amortization expense for the years ended December 31, 2004, 2003 and 2002 was approximately $457,000, $364,000, and $272,000, respectively. Amortization expense for the next five succeeding years is estimated to be approximately $483,000, $402,000, $265,000, $164,000, and $61,000, respectively.

        Basic has identified its reporting units to be well servicing, fluid services, well site construction services and drilling and completion services. The goodwill allocated to such reporting units as of December 31, 2004 is $8.8 million, $18.6 million, $3.8 million and $8.7 million, respectively. The change in the carrying amount of goodwill for the year ended December 31, 2004 of $9.6 million relates to goodwill from acquisitions and payments pursuant to contingent earn-out agreements, with approximately $900,000, $1 million, $400,000 and $7.3 million of goodwill additions relating to the well servicing, fluid services, well site construction services and the drilling and completion services 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

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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").

        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.

		Year ended December 31,
		2004			2003 as restated			2002 as restated
		(in thousands, except per share data)
Net income (loss) available to common stockholders — as reported		$	12,861		$	(2,115	)	$	(2,679	)
Add: Stock-based employee compensation expense included in statement of operations, net of tax			986			523			—
Deduct: Stock-based employee compensation expense determined under fair-value based method for all awards, net of tax			(1,283	)		(779	)		(399	)
Net income (loss) available to common stockholders — pro forma basis		$	12,564		$	(2,371	)	$	(3,078	)
Basic earnings per share of common stock:
	Historical	$	0.46		$	(0.09	)	$	(0.13	)
	Pro forma	$	0.45		$	(0.11	)	$	(0.15	)
Diluted earnings per share of common stock:
	Historical	$	0.42		$	(0.09	)	$	(0.13	)
	Pro forma	$	0.41		$	(0.11	)	$	(0.15	)

        Under SFAS No. 123, the fair value of each stock option grant is estimated on the date of grant using the Black-Scholes option pricing model with the following weighted average assumptions used for grants during the years ended December 31, 2004, 2003 and 2002:

	2004		2003		2002
Risk-free interest rate	4.4	%	2.9	%	4.3	%
Expected life	10		10		10
Expected volatility	0	%	0	%	0	%
Expected dividend yield	—		—		—

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Income Taxes

        Basic accounts 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.

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 revenues for 2004, 2003 or 2002.

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 derivatives 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 a hedging transition is highly effective in offsetting changes in the fair value or cash flows of the respective hedged item.

        Basic had no derivative contracts in 2003 and 2002. In May 2004, Basic implemented a cash flow hedge to protect itself from fluctuation in cash flows associated with its credit facility. Changes

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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 2004.

Asset Retirement Obligations

        As of January 1, 2003, Basic adopted Statement of Financial Accounting Standards No. 143, "Accounting for Asset Retirement Obligation" ("SFAS No. 143"). SFAS No. 143 requires Basic to record the fair value of an asset retirement obligation as a liability in the period in which it incurs a legal obligation associated with the retirement of tangible long-lived assets and capitalize on equal amount as a cost of the asset depreciating it over the life of the asset. Subsequent to the initial measurement of the asset retirement obligation, the obligation is adjusted at the end of each quarter to reflect the passage of time, changes in the estimated future cash flows underlying the obligation, acquisition or construction of assets, and settlements of obligations. On January 1, 2003, Basic recorded additional costs, net of accumulated depreciation of approximately $102,000, an asset retirement obligation of approximately $340,000 and an after-tax charge of approximately $151,000 for the cumulative effect on prior year's depreciation of the additional costs and the accretion expense on the liability related to the expected abandonment costs.

        Basic owns and operates salt water disposal sites, brine water wells, gravel pits and land farm sites, each of which is subject to rules and regulations regarding usage and eventual closure. The following table reflects the changes in the liability during the fiscal years ended December 31, 2004 and 2003 (in thousands):

Balance, January 1, 2003	$	—
Initial recognition of asset retirement obligation		340
Additional asset retirement obligations recognized through acquisitions		47
Accretion expense		28
Settlements		—
Balance, December 31, 2003		415
Additional asset retirement obligations recognized through acquisitions		36
Accretion expense		33
Settlements		(11	)
Balance December 31, 2004	$	473

        If SFAS No. 143 had been applied during 2002, the pro forma fair value of the asset retirement obligation included in the balance sheet would have been approximately $340,000, as of

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December 31, 2002. The pro forma net income (loss) and related per share amounts assuming SFAS No. 143 had been applied in each year are as follows (in thousands, except per share data):

		2003 (as restated)			2002 (as restated)
Pro forma net income (loss) available to common shareholders(a)		$	(1,964	)	$	(2,717	)
Pro forma earnings per share of common stock
	Basic	$	(0.09	)	$	(0.14	)
	Diluted	$	(0.09	)	$	(0.14	)

(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. The net income available to common stockholders in 2002 has been adjusted by $38,000 to reflect the pro-forma effect of 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 our past experience with similar claims. Basic maintains accruals in the consolidated balance sheets to cover self-insurance retentions (See note 7).

Comprehensive Income

        Basic follows the provisions of Statement of Financial Accounting Standards No. 130, "Reporting of Comprehensive Income" ("SFAS No. 130"). SFAS No. 130 establishes standards for reporting and presentation of comprehensive income and its components. SFAS No. 130 requires all items that are required to be recognized under accounting standards as components of comprehensive income to be reported in a financial statement that is displayed with the same prominence as other financial statements. In accordance with the provisions of SFAS No. 130, gains and losses on cash flow hedging derivatives, to the extent effective, are included in other comprehensive income (loss).

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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"). We will adopt 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 under APB No. 25. We will recognize compensation expense for awards under our Amended and Restated 2003 Incentive Plan (the "Incentive Plan") beginning in 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. 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 purchased under the Incentive Plan. Further, we have not yet determined the actual model we will use to calculate fair value.

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3.    Acquisitions

        In 2004, 2003, and 2002, 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):

	Closing Date	Total Cash Paid (net of cash acquired)
Mas-Tech	January 28, 2002	$	5,408
CJS Pinnacle Services	February 14, 2002		3,904
Tommy's Well Services	February 14, 2002		4,416
Wester Services, Inc.	June 25, 2002		3,931
B&F Services, Inc.	July 15, 2002		13,036
Advantage Services, Inc.	October 9, 2002		380
Total 2002		$	31,075
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

(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 (a) New Force Energy Services ("New Force"), FESCO Holdings, Inc. ("FESCO") and PWI, Inc. and certain other affiliated entities ("PWI") in 2003, and (b) Mas-Tech ("Mas-Tech"), Tommy's Well Services ("Tommy's") and B&F Services, Inc. ("B&F") in 2002 are deemed significant and discussed below in further detail.

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New Force Energy Services

        On January 27, 2003, Basic acquired substantially all 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 payment will be paid upon the PWI assets meeting certain financial objectives in the future. 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.

Mas-Tech

        On January 28, 2002, Basic acquired substantially all the assets of Mas-Tech for $5.4 million. The cash cost of the Mas-Tech acquisition was $5.4 million (including other direct acquisition costs)

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which was allocated $3.9 million to property and equipment, $1.5 million to goodwill, $20,000 to non-compete agreements and $4,000 to liabilities assumed.

Tommy's Well Services

        On February 14, 2002, Basic acquired substantially all the assets of Tommy's for $4.4 million and $200,000 of future well servicing services. The cash cost of the Tommy's acquisition was $4.4 million (including other direct acquisition costs) which was allocated $4.6 million to property and equipment, $25,000 to non-compete agreements and $200,000 of deferred income.

B&F Services, Inc.

        On July 15, 2002, Basic acquired substantially all the assets of B&F for $13.0 million. The cash cost of the B&F acquisition was $13.0 million (including other direct acquisition costs) which was allocated $10.9 million to property and equipment, $2.1 million to goodwill, $640,000 to inventory, $157,000 to accounts receivable $150,000 to non-compete agreements, $842,000 of assumed notes payable and $64,000 of 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 and accrued when the payment is probable. All amounts paid or accrued for related to the contingent earn-out payments are reflected as increases to the goodwill associated with the acquisition.

        The following presents a summary of acquisitions that have a contingent earn-out arrangement (in thousands):

Acquisition	Termination date of contingent earn-out arrangement	Maximum exposure of contingent earn-out arrangement		Amount paid or accrued through December 31, 2004
Advantage Services, Inc.	October 9, 2005	$	250	$	166
New Force Energy Services	January 27, 2008		2,700		916
S & S Bulk Cement	April 20, 2008		115		60
Briscoe Oil Tools	June 12, 2008		125		59
PWI, Inc.	August 14, 2008		2,500		—
Rolling Plains	April 30, 2009		*		—
		$	5,690	$	1,201

*

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

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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 Mas-Tech, Tommy's, B&F, New Force, FESCO and PWI acquisitions had been completed on January 1, 2002. 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			2002
	(as restated)			(as restated)
	(Unaudited)			(Unaudited)
Revenues	$	228,059		$	193,236
Income (loss) from continuing operations less preferred stock dividends and accretion	$	(1,182	)	$	(5,591	)
Loss per common share — basic	$	(0.05	)	$	(0.28	)
Loss per common share — diluted	$	(0.05	)	$	(0.28	)

        Basic does not believe the pro-forma effect of the other acquisitions completed in 2002, 2003, or 2004 is material to the pro-forma results of operations.

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4.    Property and Equipment

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

	December 31,
	2004		2003
Land	$	1,573	$	1,286
Buildings and improvements		6,615		5,486
Well servicing rigs and equipment		138,957		116,150
Fluid services equipment		53,111		42,427
Brine and fresh water stations		7,722		8,623
Frac/test tanks		19,707		9,954
Pressure pumping equipment		14,971		6,864
Construction equipment		21,964		19,967
Disposal facilities		14,079		11,060
Vehicles		18,881		18,890
Rental equipment		4,885		2,916
Aircraft		3,335		—
Other		7,780		5,242
		313,580		248,865
Less accumulated depreciation and amortization		80,129		60,622
Property and equipment, net	$	233,451	$	188,243

        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,
	2004		2003
Light vehicles	$	12,993	$	8,615
Fluid services equipment		10,558		5,600
Construction equipment		840		840
Other		—		521
		24,391		15,576
Less accumulated amortization		7,201		6,099
	$	17,190	$	9,477

        Amortization of assets held under capital leases of approximately $1.8 million, $2.5 million and $1.9 million for the years ended December 31, 2004, 2003 and 2002, respectively, is included in depreciation and amortization expense in the consolidated statements of operations.

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5.    Long-Term Debt

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

		December 31,
		2004		2003
Credit Facilities:
	Term B Loan	$	166,500	$	139,000
	Revolver		—		—
	Swing-line		—		—
Capital leases and other notes			15,976		9,509
			182,476		148,509
Less current portion			11,561		6,393
		$	170,915	$	142,116

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 provides for a $170 million Term B Loan ("2004 Term B Loan") and a $50 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 credits and (c) $2.5 million of swing-line loans (next day borrowing). The amounts outstanding under the 2004 Term B Loan require 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 Revolver are due and payable on October 3, 2008. The 2004 Credit Facility is 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 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 2% or (b) the LIBOR rate 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 Revolver bear 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 vary 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 are 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 is due quarterly on the available borrowings under the Revolver at rates ranging from .375% to .5%.

        At December 31, 2004, Basic, under its Revolver, had $8.3 million of outstanding letters of credit and no amounts outstanding in swing-line loans. At December 31, 2004, Basic had availability under its Revolver of $41.7 million.

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        Pursuant to the 2004 Credit Facility Basic must apply proceeds to reduce principal outstanding under the 2004 Term B Revolver from (a) individual assets sales greater than $1 million or $5 million in aggregate on an annual basis, and (b) 50% of the proceeds from any equity offering. The 2004 Credit Facility required Basic to enter into a interest rate hedge, acceptable to the lenders, for at least two years on at least $65 million of Basic's then outstanding indebtedness. Paydowns on the 2004 Term B Loan may not be reborrowed.

        The 2004 Credit Facility contains various restrictive covenants and compliance requirements, which include (a) limiting of the incurrence of additional indebtedness, (b) restrictions on merger, sales or transfer of assets without the lenders' consent, (c) limitation on dividends and distributions and (d) various financial covenants, including (1) a maximum leverage ratio of 3.6 to 1.0 reducing over time to 3.0 to 1.0, (2) a minimum fixed coverage ratio of 1.15 to 1.0 and (3) a minimum interest coverage ratio of 3.0 to 1.0. At December 31, 2004, Basic was in compliance with its covenants.

2003 Credit Facility

        On October 3, 2003, Basic entered into a $170 million credit facility with a syndicate of lenders ("2003 Credit Facility") which refinanced all of its then existing credit facilities. The 2003 Credit Facility provided for a $140 million Term B Loan ("2003 Term B Loan") and a $30 million revolving line of credit ("Revolver"). The commitment under the 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 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 or the federal funds rate plus .50% 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 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, 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 participation fees and .125% for fronting fees. A commitment fee was due quarterly on the available borrowings under the Revolver at rates ranging from .5% to .375%.

        At December 31, 2003, Basic, under its 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 Revolver of $24.7 million.

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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, 2004, the aggregate maturities of debt, including capital leases, for the next five years and thereafter are as follows (in thousands):

	Debt		Capital Leases
2005	$	7,000	$	4,561
2006		10,500		4,419
2007		10,500		3,740
2008		14,000		2,654
2009		124,500		602
Thereafter		—		—
	$	166,500	$	15,976

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

	Year ended December 31,
	2004		2003		2002
Cash payments for interest	$	8,159	$	3,934	$	4,066
Commitment and other fees paid		25		109		—
Amortization of debt issuance costs		970		694		766
Other		560		497		—
	$	9,714	$	5,234	$	4,832

Losses on Extinguishment of Debt

        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 and has reclassified such gains and losses in the consolidated financial statements for 2002 to conform to the presentation in future years.

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6.    Income Taxes

        Income tax provision (benefit) was allocated as follows (in thousands):

	Years ended December 31,
	2004			2003			2002
				(as restated)			(as restated)
Income (loss) from continuing operations	$	7,984		$	2,772		$	(382	)
Discontinued operations		(38	)		13			—
Cumulative effect of accounting change		—			(88	)		—
	$	7,946		$	2,697		$	(382	)

        Income tax expense (benefit) attributable to income (loss) from continuing operations consists of the following (in thousands):

	Years ended December 31,
	2004		2003			2002
			(as restated)			(as restated)
Current	$	—	$	(68	)	$	(1,918	)
Deferred		7,984		2,840			1,536
	$	7,984	$	2,772		$	(382	)

        No federal income taxes were paid or received in 2004. In 2003 and 2002, Basic received an income tax refund, net, of approximately $1.5 million and $2.8 million respectively.

        Reconciliation between the amount determined by applying the federal statutory rate (35% in 2004 and 2003; 34% in 2002) to the income (loss) from continuing operations with the provision (benefit) for income taxes is as follows (in thousands):

	Years ended December 31,
	2004			2003			2002
				(as restated)			(as restated)
Statutory federal income tax	$	7,321		$	2,007		$	(548	)
Amortization of non-deductible goodwill and property		—			—			8
Meals and entertainment		265			166			112
State taxes, net of federal benefit		421			138			(43	)
Change in tax rates		—			542			—
Changes in estimates and other		(23	)		(81	)		89
	$	7,984		$	2,772		$	(382	)

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        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,
			2004			2003
Current deferred taxes:
	Receivables allowance		$	1,148		$	723
	EBITDA contingent warrants			337			337
	Accrued liabilities			3,414			2,582
		Net current deferred tax asset	$	4,899		$	3,642
Noncurrent deferred taxes:
	Operating loss and tax credit carryforwards		$	20,782		$	18,673
	Property and equipment			(51,194	)		(37,201	)
	Goodwill and intangibles			(602	)		72
	Deferred Compensation			617			—
	Asset retirement obligation			175			153
	Other			(25	)		36
		Net noncurrent deferred tax liability	$	(30,247	)	$	(18,267	)

        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, 2004 or 2003.

        As of December 31, 2004, Basic had approximately $55.9 million of net operating loss carryforwards ("NOL") for U.S. federal income tax purposes. Approximately $7.0 million of the NOL relates to the preacquisition period of FESCO, which are subject to an annual limitation of approximately $900,000. The carryforwards begin to expire in 2017.

7.    Commitments and Contingencies

Environmental

        Basic is subject to various federal, state and local environmental laws and regulations that establish standards and requirements for protection of the environment. Basic cannot predict the future impact of such standards and requirements which are subject to change and can have retroactive effectiveness. Basic continues to monitor the status of these laws and regulations. Management 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

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expenditures is not determinable due to several factors including the unknown magnitude of possible contamination, the unknown timing and extent of the corrective actions which may be required, the determination of Basic's liability in proportion to other responsible parties and the extent to which such expenditures are recoverable from insurance or indemnification.

Litigation

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

Operating Leases

        Basic leases certain property and equipment under non-cancelable operating leases. The term of the operating leases generally range from 12 to 60 months with varying payment dates throughout each month.

        As of December 31, 2004, the future minimum lease payments under non-cancelable operating leases are as follows (in thousands):

Year ended December 31,
2005	$	818
2006		601
2007		416
2008		384
2009		257
Thereafter		715

        Rent expense approximated $5.6 million, $3.0 million, and $1.6 million for 2004, 2003, and 2002, 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

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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 $100,000, respectively. Basic has lower deductibles per occurrence for automobile liability and general liability. Basic maintains accruals in the accompanying consolidated balance sheets related to self-insurance retentions by using third-party data and historical claims history.

        At December 31, 2004 and 2003, self-insured risk accruals, net of related recoveries/receivables totaled approximately $6.6 million and $4.3 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 at 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 stock of FESCO. See note 3.

        In February 2004, Basic granted certain officers and directors 837,500 restricted shares of common stock. The shares vest 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 $1.3 million for the year ended December 31, 2004.

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Preferred Stock

        In June 2002, Basic issued 150,000 shares of mandatorily redeemable Series A 10% Cumulative Preferred Stock ("Series A Preferred Stock") to a group of investors for $15 million or $100 per share. After deducting fees, this resulted in net proceeds to Basic totaling approximately $14.9 million.

        Dividends on each share of Series A Preferred Stock accrued on a daily basis at the rate of 10% per annum of the sum of the Liquidation Value ($100) thereof plus all accrued and unpaid dividends thereon from and including the date of issuance of such share. All dividends which had accrued on the Series A Preferred Stock were payable on March 31, June 30, September 30 and December 31 of each year, beginning September 30, 2002. All dividends which had accrued on Series A shares outstanding remained as accumulated dividends until paid to the holders thereof.

        Basic could redeem all or any portion of the Series A Preferred Stock by paying a price per share equal to the Liquidation Value ($100) plus all accrued and unpaid dividends plus a premium equal to 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 paid-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, 2004. 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.

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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. These rights include the right to cause the board to nominate, and the other stockholders to vote on, the election of directors. The funds affiliated with DLJ Merchant Banking have the right to designate four directors or if there are more than six directors, such number of directors as most closely approximates ²/3 of the aggregate number of directors. Southwest Royalties Holdings, Inc. and its affiliates have the right to designate one director. The chief executive officer of Basic is entitled to designate himself as a director so long as he is party to an employment agreement with Basic that requires him to receive a position on the board. These rights with respect to the election or designation of directors will terminate upon an initial public offering of Basic's common stock.

        The Stockholders' Agreement also provides for preemptive rights on our issuance of additional shares, other than pursuant to any public offering of common stock, as consideration in connection with an acquisition, as awards to employees, directors, consultants or advisors that are approved by the board of directors, or equity securities (including convertible debt or warrants) issued as or in connection with a loan or debt financing. These preemptive rights will terminate upon an initial public offering of Basic's common stock.

        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 an initial public offering). During this period, stockholders are generally prohibited from transferring shares to persons other than permitted assignees. The Stockholders' Agreement provides for participation rights of the other stockholders to require affiliates of DLJ Merchant Banking to offer to include a specified percentage of their shares whenever affiliates of DLJ Merchant Banking sell their shares for value, other than a public offering or a sale in which all of the parties to the Stockholders' Agreement agree to participate. The Stockholders' Agreement also contains "drag-along" rights. The "drag-along" rights entitle the affiliates 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.

        Additional special restrictions apply to officers or directors who own shares of common stock or common stock equivalents. Shares owned by these persons are subject to purchase by Basic, at Basic's option, in the event the company terminates the officer or director for Cause (as defined in the agreement), or the holder terminates his employment without Good Reason (as defined in the agreement). The purchase price for this repurchase is the lesser of their fair market value or their book value, computed in accordance with generally accepted accounting principles, as of the end of the most recent completed fiscal quarter. In the event Basic terminates an officer as an employee other than for Cause, an officer terminates his employment for Good Reason, an officer's employment terminates as a result of a permanent disability, retirement or death, or a non-employee director ceases to be a member of the board of directors, then such person is

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required to sell, and Basic is required to purchase, shares of common stock or common stock equivalents at their fair market value. In the event of a divorce of an officer or director from his/her spouse, if shares of common stock or common stock equivalents previously owned by such officer or director are allocated to such spouse, the officer or director and Basic shall have the option to purchase such shares at their fair market value, unless the spouse is a registered stockholder of Basic prior to the divorce. If the spouse of an officer or director dies and it is determined that shares of common stock or common stock equivalents held of record by the deceased spouse would not vest in the officer or director, then such officer or director and Basic have the option to purchase the non-vested shares at their fair market value. In the event of a bankruptcy of an officer or director, shares of Basic common stock or common stock equivalents owned by such person are subject to purchase by Basic, at Basic's option, at their fair market value. These special restrictions will terminate upon an initial public offering of Basic's common stock.

        The Stockholders' Agreement also provides 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 remain 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, 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.

        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.

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        The following table reflects the summary of the stock options outstanding for the years ended December 31, 2004, 2003 and 2002 and the changes during the years then ended:

			2004					2003					2002
			Number of options			Weighted average price		Number of options			Weighted average price		Number of options			Weighted average price
Non-statutory stock options:
	Outstanding, beginning of year			1,290,800		$	4.03		700,800		$	4.00		882,500		$	4.00
		Options granted		197,500		$	5.16		642,500		$	4.06		—		$	—
		Options forfeited		(25,000	)	$	5.16		(52,500	)	$	4.00		(181,700	)	$	4.00
		Options exercised		—		$	—		—		$	—		—		$	—
Outstanding, end of year				1,463,300		$	4.17		1,290,800		$	4.03		700,800		$	4.00
Exercisable, end of year				872,440					421,675					254,125
Weighted average fair value of options granted during the year			$	3.14				$	1.61				$	—

        The following table summarizes information about Basic's stock options outstanding and options exercisable at December 31, 2004:

	Options Outstanding				Options Exercisable
Range of Exercise Prices	Number of Options Outstanding at December 31, 2004	Weighted Average Remaining Contractual Life	Weighted Average Exercise Price		Number of Options Outstanding at December 31, 2004	Weighted Average Exercise Price
$4.00	1,253,300	7.43 years	$	4.00	872,440	$	4.00
$5.16	210,000	9.23 years	$	5.16	—	$	—
	1,463,300				872,440

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 on 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.

F1-31

        On August 23, 2001, Basic issued additional EBITDA Contingent Warrants to purchase up to an aggregate of 106,310 shares, at $0.01 per share, of Basic's common stock as part of an authorized issuance to certain members of its management. The determination of the ultimate number of EBITDA Contingent Warrants that may be exercised was dependent on Basic's achieving certain levels of financial performance in 2001 and 2002. The warrants became exercisable, and were not subject to forfeiture for termination, no later than March 31, 2003 based on actual financial performance for 2001 and 2002 and expired on May 1, 2003.

        In 2003, it was determined that Basic did not meet the financial performance objectives as set forth in the EBITDA Contingent Warrant grants. However, the board of directors evaluated other subjective matters regarding these grants and authorized the award of 574,860 warrants to the stockholders and 196,880 warrants to certain members of management even though the performance criteria was not met. As a result, Basic recognized the compensation expense of $911,000 related to the portion of the warrants issued to management in 2003. In 2003, all holders of the warrants exercised all of their rights and acquired common stock of Basic. The value of the warrants associated with the common stock dividend was recorded in 2003 when the number of warrants to be issued was known.

12.    Related Party Transactions

        Basic provided services and products for workover, maintenance and plugging of existing oil and gas wells to Southwest Royalties, Inc., an affiliate of a director and other significant stockholders of Basic, for approximately $140,000, $1.3 million, and $800,000, in 2004, 2003 and 2002, respectively. Basic had receivables from Southwest Royalties, Inc. of approximately $0 and $85,000 as of December 31, 2004 and 2003, respectively, which are included in accounts receivable — related parties in the consolidated balance sheets.

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 $363,000, $180,000, and $122,000 in 2004, 2003, and 2002, respectively.

14.    Earnings Per Share

        Basic presents earnings per share information in accordance with the provisions of Statement of Financial Accounting Standards No. 128, "Earnings per Share" ("SFAS No. 128"). Under SFAS No. 128, basic earnings per common share are determined by dividing net earnings applicable to common stock by the weighted average number of common shares actually outstanding during the year. Diluted earnings per common share is based on the increased number of shares that would be outstanding assuming conversion of dilutive outstanding securities using the "as if converted"

F1-32

method. The following table sets forth the computation of basic and diluted earnings per share. (in thousands, except share data):

		Years ended December 31,
		2004			2003			2002
					(as restated)			(as restated)
Numerator (both basic and diluted):
	Income (loss) from continuing operations less preferred stock dividends and accretion	$	12,932		$	(1,986	)	$	(2,679	)
	Discontinued operations, net of tax		(71	)		22			—
	Cumulative effect of accounting change		—			(151	)		—
	Net income (loss) available to common stockholders	$	12,861		$	(2,115	)	$	(2,679	)
Denominator:
	Weighted average common stock outstanding		28,094,435			22,575,940			20,006,965
	Denominator for basic earnings per share		28,094,435			22,575,940			20,006,965
	Stock options		389,975			—			—
	Restricted stock		711,645			—			—
	Common stock warrants		1,333,310			—			—
	Denominator for diluted earnings per share		30,529,365			22,575,940			20,006,965
Basic earnings per common share:
	Income (loss) from continuing operations less preferred stock dividends and accretion	$	0.46		$	(0.09	)	$	(0.13	)
	Discontinued operations, net of tax		—			—			—
	Cumulative effect of accounting change		—			—			—
	Net income (loss) available to common stockholders	$	0.46		$	(0.09	)	$	(0.13	)
Diluted earnings per common share:
	Income (loss) from continuing operations less preferred stock dividends and accretion	$	0.42		$	(0.09	)	$	(0.13	)
	Discontinued operations, net of tax		—			—			—
	Cumulative effect of accounting change		—			—			—
	Net income (loss) available to common stockholders	$	0.42		$	(0.09	)	$	(0.13	)

        The diluted earnings per share calculation for 2003 and 2002 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.

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15.    Assets Held for Sale and Discontinued Operations

        In August, 2003 Basic's management and board of directors made the decision to dispose of its fluid services operations in Alaska it acquired in the FESCO acquisition prior to closing of the acquisition. After this disposal Basic no longer had any operations in Alaska.

        The following are the results of operations, since their acquisition in October 2003, from the discontinued operations (in thousands):

		Year ended December 31,
		2004			2003
Revenues		$	1,705		$	550
Operating costs			(1,814	)		(515	)
Income taxes — deferred			38			(13	)
	Income (loss) from discontinued operations, net of tax	$	(71	)	$	22

16.    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. Our 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. We employ 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. We employ these assets to provide services for the construction and maintenance of oil and gas production infrastructure, such as preparing and maintaining access roads and well locations, installation of small diameter gathering lines and pipelines and construction of temporary foundations to support drilling rigs.

        Basic's management evaluates the performance of its operating segments based on operating revenues and segment profits. Corporate expenses include general corporate expenses associated

F1-34

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 our reportable segments (in thousands):

	Well Servicing			Fluid Services			Well Site Construction Services			Drilling and Completion Services			Corporate and Other		Total
Year ended December 31, 2004:
Operating revenues	$	142,551		$	98,683		$	40,927		$	29,341		$	—	$	311,502
Direct operating costs		(98,058	)		(65,167	)		(31,454	)		(17,481	)		—		(212,160	)
Segment profits	$	44,493		$	33,516		$	9,473		$	11,860		$	—	$	99,342
Depreciation and amortization	$	14,125		$	8,316		$	1,857		$	2,402		$	1,976	$	28,676
Capital expenditures (excluding acquisitions)	$	27,918		$	16,436		$	4,748		$	3,670		$	2,902	$	55,674
Identifiable assets	$	126,208		$	87,349		$	24,064		$	24,246		$	105,993	$	367,860
Year ended December 31, 2003:
Operating revenues	$	104,097		$	52,810		$	9,184		$	14,808		$	—	$	180,899
Direct operating costs		(73,244	)		(34,420	)		(6,586	)		(9,363	)		—		(123,613	)
Segment profits	$	30,853		$	18,390		$	2,598		$	5,445		$	—	$	57,286
Depreciation and amortization	$	9,100		$	5,201		$	850		$	2,575		$	487	$	18,213
Capital expenditures (excluding acquisitions)	$	13,217		$	6,298		$	2,412		$	676		$	898	$	23,501
Identifiable assets	$	102,948		$	73,841		$	31,322		$	10,387		$	84,155	$	302,653
Year ended December 31, 2002:
Operating revenues	$	73,848		$	34,170		$	—		$	733		$	—	$	108,751
Direct operating costs		(55,643	)		(22,705	)		—			(512	)		—		(78,860	)
Segment profits	$	18,205		$	11,465		$	—		$	221		$	—	$	29,891
Depreciation and amortization	$	9,038		$	4,242		$	5		$	—		$	129	$	13,414
Capital expenditures (excluding acquisitions)	$	8,817		$	4,734		$	—		$	—		$	1,123	$	14,674
Identifiable assets	$	82,855		$	45,262		$	—		$	44		$	28,341	$	156,502

        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,
	2004			2003			2002
				(as restated)			(as restated)
Segment profits	$	99,342		$	57,286		$	29,891
General and administrative expenses		(37,186	)		(22,722	)		(13,019	)
Depreciation and amortization		(28,676	)		(18,213	)		(13,414	)
Gain (loss) on disposal of assets		(2,616	)		(391	)		(351	)
Operating income	$	30,864		$	15,960		$	3,107

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17.    Accrued Expenses

        The accrued expenses are as follows (in thousands):

	December 31,
	2004		2003
Compensation related	$	6,764	$	6,804
Workers' compensation self-insured risk reserve		5,469		2,328
Health self-insured risk reserve		1,490		2,348
Accrual for receipts		903		599
Authority for expenditure accrual		879		—
Ad valorem taxes		845		1,117
Sales tax		692		389
Insurance obligations		586		3,613
Purchase order accrual		409		—
Professional fee accrual		392		183
Diesel tax accrual		336		273
Acquired contingent earnout obligation		273		849
Retainers		250		51
Fuel accrual		317		172
Accrued interest		232		792
Other		649		232
	$	20,486	$	19,750

18.    Supplemental Schedule of Non-Cash Investing and Financing Activities

	Year ended December 31,
	2004		2003		2002
	(as restated)
	(in thousands)
Capital leases issued for equipment	$	10,472	$	10,782	$	2,445
Preferred stock dividend		—		1,525		1,075
Preferred stock discount		—		—		4,299
Preferred stock issued to pay accrued dividends		—		902		—
Accretion of preferred stock discount		—		3,424		374
Common stock issued for FESCO acquisition		—		18,827		—
Common stock issued for preferred stock		—		17,029		—
Vehicle rebate accrual		709		—		—

19.    Subsequent Events

(a)   Acquisitions

        On January 5, 2005, Basic acquired all of the capital stock of R & R Hot Oil Service, Inc. and related real estate for $1.4 million, subject to adjustments. This acquisition will operate in Basic's fluid services line of business in the Rocky Mountain division.

F1-36

        On January 28, 2005, Basic purchased the operating assets of Premier Vacuum Service, Inc. ("Premier") for $1 million, subject to adjustments. One of the selling shareholders is a related party. This acquisition will operate in Basic's fluid services line of business in the South Texas division.

        On February 9, 2005, Basic purchased the operating assets of Spencer's Coating Specialist Company, Inc. for $615,000 subject to adjustments. This acquisition will operate in Basic's well services line of business in the Permian division.

        On February 25, 2005, Basic purchased the assets of Mark's Well Service, Inc. for $575,000, subject to adjustments. This acquisition will operate in Basic's well services line of business in the North Texas division.

        On April 28, 2005, Basic purchased substantially all the assets of Max-Line, Inc. for $1.5 million, subject to adjustments. This acquisition will operate in Basic's drilling and completion line of business in the North Texas division.

        On May 17, 2005, Basic purchased substantially all the assets of MD Well Service, Inc/D&L Enterprises Corp. for $6.0 million, subject to adjustments. This acquisition will operate in Basic's well services line of business in the Rocky Mountain division.

(b)   Litigation

        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 has denied coverage of liability. Basic plans to appeal this verdict.

(c)   Stock Split

        On August 3, 2005 the board of directors of Basic approved a resolution to effect a 5-for-1 stock split of its common stock in the form of a stock dividend resulting in 28,931,935 shares of common stock outstanding and to amend its 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 years 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.

20.    Restatement of Prior Periods

        In 2005, Basic determined that its 2003 and 2002 consolidated financial statements required restatement for the following items:

        Basic reviewed the accounting treatment associated with the EBITDA Contingent Warrants issued to management (see note 11) and determined since the original performance criteria in the warrant agreements was not met, that compensation expense should not have been recorded until 2003 when the board of directors decided to grant 50% of the warrants even though the performance criteria was not met. The result of this change was to reduce compensation expense in 2001 and 2002 by approximately $684,000 and $105,000, respectively, and to record additional

F1-37

compensation expense in 2003 of approximately $789,000. In addition, Basic reviewed the accounting treatement associated with the conversion of the Series A Preferred Stock into common stock (see note 8) and determined that the excess of the consideration received by the preferred shareholders over the book value of the preferred stock at the conversion date should have been treated as a reduction of net income available to common stockholders. The result of this change was to decrease net income available to common stockholders in 2003 by $2,884,000.

        The following presents the impact of the restatement on the operating results for the years ended December 31, 2003 and 2002:

		Year Ended December 31, 2003						Year Ended December 31, 2002
		Previously Reported			As Restated			Previously Reported			As Restated
		(in thousands except per share data)
General and administrative expense		$	21,933		$	22,722		$	13,124		$	13,019
Total expenses			164,150			164,939			105,749			105,644
Operating income			16,749			15,960			3,002			3,107
Income (loss) from continuing operations before income taxes			6,524			5,735			(1,717	)		(1,612	)
Income tax (expense) benefit			(3,048	)		(2,772	)		419			382
Income (loss) from continuing operations			3,476			2,963			(1,298	)		(1,230	)
Net income (loss)			3,347			2,834			(1,298	)		(1,230	)
Accretion of preferred stock discount			(540	)		(3,424	)		(374	)		(374	)
Net income (loss) available to common stockholders			1,282			(2,115	)		(2,747	)		(2,679	)
Basic earnings per share of common stock:
	Continuing operations		0.06			(0.09	)		(0.13	)		(0.13	)
	Net income (loss) available to common stockholders		0.05			(0.09	)		(0.13	)		(0.13	)
Diluted earnings per share of common stock:
	Continuing operations		0.06			(0.09	)		(0.13	)		(0.13	)
	Net income (loss) available to common stockholders		0.05			(0.09	)		(0.13	)		(0.13	)
Comprehensive income (loss)			3,347			2,834			(1,298	)		(1,230	)

        The following presents the impact of the restatement on the balance sheets as of December 31, 2004 and 2003.

	December 31, 2004				December 31, 2003
	Previously Reported		As Restated		Previously Reported		As Restated
Additional paid-in capital	139,004		142,802		132,726		136,524
Accumulated deficit	(12,329	)	(16,127	)	(25,190	)	(28,988	)

F1-38

Basic Energy Services, Inc.

Consolidated Balance Sheets

(in thousands, except share data)

			June 30, 2005			December 31, 2004
			(Unaudited)
ASSETS
Current assets:
	Cash and cash equivalents		$	14,066		$	20,147
	Trade accounts receivable, net of allowance of $4,008 and $3,108, respectively			67,105			56,651
	Accounts receivable — related parties			108			103
	Income tax refund receivable			355			355
	Inventories			1,387			1,176
	Prepaid expenses			1,428			1,798
	Other current assets			1,772			2,099
	Deferred tax assets			6,947			4,899
		Total current assets		93,168			87,228
Property and equipment, net				264,758			233,451
Deferred debt costs, net of amortization				4,190			4,709
Goodwill				42,372			39,853
Other assets				2,422			2,360
			$	406,910		$	367,601
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
	Accounts payable		$	10,288		$	11,388
	Accrued expenses			30,849			20,486
	Income taxes payable			1,681			—
	Current portion of long-term debt			14,072			11,561
	Other current liabilities			862			545
		Total current liabilities		57,752			43,980
Long-term debt				166,442			170,915
Deferred income				23			44
Deferred tax liabilities				41,057			30,247
Other long-term liabilities				1,683			629
Commitments and contingencies
Stockholders' equity:
	Common stock; $.01 par value; 80,000,000 shares authorized; 28,931,935 issued 28,920,685 and 28,931,935 outstanding at June 30, 2005 and December 31, 2004, respectively			58			58
	Additional paid-in capital			148,228			142,802
	Deferred compensation			(9,057	)		(4,990	)
	Retained earnings (deficit)			421			(16,127	)
	Treasury stock, 11,250 shares at June 30, 2005, at cost			—			—
	Accumulated other comprehensive income			303			43
		Total stockholders' equity		139,953			121,786
			$	406,910		$	367,601

See accompanying notes to consolidated financial statements.

F1-39

Basic Energy Services, Inc.

Consolidated Statements of Operations and Comprehensive Income

(Dollars in thousands, except per share amounts)

			Six Months Ended June 30,
			2005			2004
			(unaudited)
Revenues:
	Well servicing		$	98,650		$	66,098
	Fluid services			60,839			45,006
	Drilling and completion services			24,276			12,116
	Well site construction services			19,866			18,645
		Total revenues		203,631			141,865
Expenses:
	Well servicing			61,464			45,416
	Fluid services			39,119			29,743
	Drilling and completion services			12,731			7,057
	Well site construction services			14,663			14,384
	General and administrative, including stock-based compensation of $1,359 and $631 in 2005 and 2004, respectively			26,463			16,780
	Depreciation and amortization			16,818			12,778
	Loss (gain) on disposal of assets			(50	)		1,863
		Total expenses		171,208			128,021
		Operating income		32,423			13,844
Other income (expense):
	Interest expense			(6,201	)		(4,246	)
	Interest income			199			84
	Other income (expense)			137			25
Income from continuing operations before income taxes				26,558			9,707
Income tax expense				(10,010	)		(3,705	)
Income from continuing operations				16,548			6,002
Discontinued operations, net of tax				—			88
Net income			$	16,548		$	6,090
Basic earnings per share of common stock:
	Continuing operations		$	0.58		$	0.21
	Discontinued operations			—			0.01
	Net income available to common stockholders		$	0.58		$	0.22
Diluted earnings per share of common stock:
	Continuing operations		$	0.51		$	0.19
	Discontinued operations			—			0.01
	Net income available to common stockholders		$	0.51		$	0.20
Comprehensive Income:
Net income			$	16,548		$	6,090
Unrealized gains (losses) on hedging activities				260			(88	)
Comprehensive Income:			$	16,808		$	6,002

See accompanying notes to consolidated financial statements.

F1-40

Basic Energy Services, Inc.

Consolidated Statements of Stockholders' Equity

(in thousands, except share data)

	Common Stock												Accumulated Other Comprehensive Income
				Additional Paid-In Capital		Deferred Compensation			Treasury Stock	Retained Earnings (Deficit)					Total Stockholders' Equity
	Shares	Amount
Balance — December 31, 2004	28,931,935	$	58	$	142,802	$	(4,990	)	—	$	(16,127	)	$	43	$	121,786
Stock-based compensation awards	—		—		5,426		(5,426	)	—		—			—		—
Amortization of deferred compensation	—		—		—		1,359		—		—			—		1,359
Unrealized gain on interest rate swap agreement	—		—		—		—		—		—			260		260
Forfeited 11,250 shares at cost of $0	—		—		—		—		—		—			—		—
Net income	—		—		—		—		—		16,548			—		16,548
Balance — June 30, 2005 (Unaudited)	28,931,935	$	58	$	148,228	$	(9,057	)	—	$	421		$	303	$	139,953

See accompanying notes to consolidated financial statements.

F1-41

Basic Energy Services, Inc.

Consolidated Statements of Cash Flows

(in thousands)

					Six Months Ended June 30,
					2005			2004
					(Unaudited)
Cash flows from operating activities:
	Net income				$	16,548		$	6,090
		Adjustments to reconcile net income to net cash provided by operating activities:
			Depreciation and amortization			16,818			12,778
			Accretion on asset retirement obligation			18			16
			Change in allowance for doubtful accounts			900			559
			Non-cash interest expense			527			431
			Non-cash compensation			1,359			631
			(Gain) loss on disposal of assets			(50	)		1,863
			Deferred income taxes			8,274			3,661
		Changes in operating assets and liabilities, net of acquisitions:
			Accounts receivable			(11,222	)		(9,996	)
			Inventories			(211	)		13
			Income tax receivable			—			83
			Prepaid expenses and other current assets			1,325			691
			Other assets			(201	)		(362	)
			Accounts payable			(1,103	)		4,271
			Income tax payable			1,681			—
			Deferred income and other liabilities			(167	)		(141	)
			Accrued expenses			10,327			(903	)
				Net cash provided by operating activities		44,823			19,685
	Cash flows from investing activities:
		Purchase of property and equipment				(35,488	)		(23,928	)
		Proceeds from sale of assets				877			815
		Payments for other long-term assets				(858	)		(256	)
		Payments for businesses, net of cash acquired				(9,885	)		(5,434	)
				Net cash used in investing activities		(45,354	)		(28,803	)
	Cash flows from financing activities:
		Proceeds from debt				294			—
		Payments of debt				(5,836	)		(2,661	)
		Deferred loan costs and other financing activities				(8	)		—
				Net cash provided by (used in) financing activities		(5,550	)		(2,661	)
				Net increase (decrease) in cash and equivalents		(6,081	)		(11,779	)
	Cash and cash equivalents — beginning of period					20,147			25,697
	Cash and cash equivalents — end of period				$	14,066		$	13,918

See accompanying notes to consolidated financial statements.

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Basic Energy Services, Inc.

Notes To Consolidated Financial Statements

June 30, 2005

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.

        The accompanying unaudited financial statements have been prepared in accordance with accounting principles generally accepted in the United States for interim financial reporting. Accordingly, they do not include all of the information and footnotes required by accounting principles generally accepted in the United States for complete financial statements. In the opinion of management, all adjustments considered necessary for a fair presentation have been made in the accompanying unaudited financial statements.

Nature of Operations

        Basic provides a range of well site services to oil and gas drilling and producing companies, including well servicing, fluid services, drilling and completion services and well site construction services. These services are primarily provided by Basic's fleet of equipment. Basic's operations are concentrated in the major United States onshore oil and gas producing regions of the states of 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. 46 or Accounting Research Bulletin No. 51. All inter-company transactions and balances have been eliminated.

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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.

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.

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.

Impairments

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

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

        Basic had no impairment expense in 2005 or 2004.

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Deferred Debt Costs

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

        Deferred debt costs of approximately $5.8 million at June 30, 2005 and December 31, 2004, respectively, represent debt issuance costs and are recorded net of accumulated amortization of $1.6 million and $1.1 million at June 30, 2005 and December 31, 2004, respectively. Amortization of deferred debt costs totaled approximately $527,000 and $431,000 for the six months ended June 30, 2005 and 2004, respectively.

Goodwill

        Statement of Financial Accounting Standards No. 142, Goodwill and Other Intangible Assets ("SFAS No. 142") eliminates the amortization of goodwill and other intangible assets with indefinite lives. Intangible assets with lives restricted by contractual, legal, or other means will continue to be amortized over their useful lives. Goodwill and other intangible assets not subject to amortization are tested for impairment annually or more frequently if events or changes in circumstances indicate that the asset might be impaired. SFAS No. 142 requires a two-step process for testing impairment. First, the fair value of each reporting unit is compared to its carrying value to determine whether an indication of impairment exists. If impairment is indicated, then the fair value of the reporting unit's goodwill is determined by allocating the unit's fair value to its assets and liabilities (including any unrecognized intangible assets) as if the reporting unit had been acquired in a business combination. The amount of impairment for goodwill is measured as the excess of its carrying value over its fair value. Basic completed its assessment of goodwill impairment as of the date of adoption and completed a subsequent annual impairment assessment as of December 31, 2004. 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 June 30, 2005 is $9.8 million, $19.3 million, $9.5 million and $3.8 million, respectively. The change in the carrying amount of goodwill for the six months ended June 30, 2005 of $2.5 million relates to goodwill from acquisitions and payments pursuant to contingent earn-out agreements, with approximately $1,093,000, $866,000 and $561,000 of goodwill additions relating to the well servicing, fluid services and drilling and completion units, respectively.

Stock-Based Compensation

        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

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the effect on net income if Basic had applied the fair value recognition provisions of SFAS No. 123 to stock-based employee compensation.

		Six months ended June 30,
		2005			2004
		(Unaudited)
Net income available to common stockholders — as reported		$	16,548		$	6,090
Add: Stock-based employee compensation expense included in statement of operations, net of tax			854			393
Deduct: Stock-based employee compensation expense determined under fair-value based method for all awards, net of tax			(1,113	)		(647	)
Net income available to common stockholders — pro forma basis		$	16,289		$	5,836
Basic earnings per share of common stock:
	As reported	$	0.58		$	0.22
	Pro forma	$	0.57		$	0.21
Diluted earnings per share of common stock:
	As reported	$	0.51		$	0.20
	Pro forma	$	0.50		$	0.19

        Under SFAS No. 123, the fair value of each stock option grant is estimated on the date of grant using the Black-Scholes option pricing model with the following weighted average assumptions used for grants during the six months ended June 30, 2005 and 2004:

	2005		2004
Risk-free interest rate	4.5	%	4.0	%
Expected life	10		10
Expected volatility	0	%	0	%
Expected dividend yield	—		—

        During the six months ended June 30, 2005, Basic granted stock options with exercise prices as follows:

Grants Made	Number of Options Granted	Weighted Average Exercise Price		Weighted Average Fair Value Per Share		Weighted Average Intrinsic Value Per Share
January 26, 2005	100,000	$	5.16	$	9.63	$	4.47
March 2, 2005	865,000	$	6.98	$	12.78	$	5.80
May 16, 2005	5,000	$	6.98	$	15.48	$	8.50

        The intrinsic value per share is being recognized as compensation expense over the applicable service period.

Asset Retirement Obligations

        Basic owns and operates salt water disposal sites, brine water wells, gravel pits and land farm sites, each of which is subject to rules and regulations regarding usage and eventual closure. The

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following table reflects the changes in the liability during the six month period ended June 30, 2005 (in thousands):

Balance, December 31, 2004	$	473
Additional asset retirement obligations recognized through acquisitions		44
Retirements		(20	)
Accretion expense		18
Balance, June 30, 2005 (Unaudited)	$	515

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. Basic maintains accruals in the consolidated balance sheets to cover self-insurance retentions.

Reclassifications

        Certain reclassifications of prior year financial statement amounts have been made to conform to current year presentations.

Recent Accounting Pronouncements

        In March 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.

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        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. 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 purchased under the Incentive Plan. Further, Basic has not yet determined the actual model it will use to calculate fair value.

3.    Acquisitions

        In 2005 and 2004 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):

	Closing Date	Total Cash Paid (net of cash acquired)
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
Total 2005 (Unaudited)		$	9,885

        The operations of each of the acquisitions listed above are included in Basic's statement of operations as of each respective closing date.

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

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amounts paid or reasonably accrued for related to the contingent earn-out payments are reflected as increases to the goodwill associated with the acquisition.

        Basic does not believe the pro-forma effect of the acquisitions completed in 2004 or 2005 is material to the pro-forma results of operations.

4.    Property and Equipment

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

	June 30, 2005		December 31, 2004
	(Unaudited)
Land	$	1,879	$	1,573
Buildings and improvements		7,676		6,615
Well service units and equipment		170,540		138,957
Fluid services equipment		55,454		53,111
Brine and fresh water stations		7,653		7,722
Frac/test tanks		21,576		19,707
Pressure pumping equipment		19,965		14,971
Construction equipment		21,999		21,964
Disposal facilities		14,797		14,079
Vehicles		20,569		18,881
Rental equipment		5,739		4,885
Aircraft		3,236		3,335
Other		8,192		7,780
		359,275		313,580
Less accumulated depreciation and amortization		94,517		80,129
Property and equipment, net	$	264,758	$	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):

	June 30, 2005		December 31, 2004
	(Unaudited)
Light vehicles	$	14,979	$	12,993
Fluid services equipment		11,791		10,558
Construction equipment		840		840
		27,610		24,391
Less accumulated amortization		7,821		7,201
	$	19,789	$	17,190

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        Amortization of assets held under capital leases of approximately $858,000 and $562,000 for the six months ended June 30, 2005 and 2004, respectively, is included in depreciation and amortization expense in the consolidated statements of operations.

5.    Long-Term Debt

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

		June 30, 2005		December 31, 2004
		(Unaudited)
Credit Facilities:
	Term B Loan	$	163,000	$	166,500
Capital leases and other notes			17,514		15,976
			180,514		182,476
Less current portion			14,072		11,561
		$	166,442	$	170,915

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 provides for a $170 million Term B Loan ("2004 Term B Loan") and a $50 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 2004 Term B Loan require 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 Revolver are due and payable on October 3, 2008. The 2004 Credit Facility is 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 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 2% or (b) LIBOR plus 3%. At June 30, 2005 and December 31, 2004, Basic's weighted average interest rate on its 2004 Term B Loan was 5.55%.

        At Basic's option, borrowings under the Revolver bear 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) LIBOR plus a margin ranging from 2.5% to 3.0%. The margins vary 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 are 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 is due quarterly on the available borrowings under the Revolver at rates ranging from .375% to ..5%.

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        At June 30, 2005 and December 31, 2004, Basic, under its Revolver, had outstanding $8.3 million of letters of credit and no amounts outstanding in swing-line loans. At June 30, 2005 and December 31, 2004, Basic had availability under its Revolver of $41.7 million.

        Pursuant to the 2004 Credit Facility Basic must apply proceeds to reduce principal outstanding under the 2004 Term B Revolver from (a) individual assets sales greater than $1 million or $5 million in the aggregate on an annual basis, and (b) 50% of the proceeds from any equity offering. The 2004 Credit Facility required Basic to enter into an interest rate hedge, acceptable to the lenders, for at least two years on at least $65 million of Basic's then outstanding indebtedness. Paydowns on the 2004 Term B Loan may not be reborrowed.

        The 2004 Credit Facility contains various restrictive covenants and compliance requirements, which include (a) limiting of the incurrence of additional indebtedness, (b) restrictions on mergers and 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 3.6 to 1.0 reducing over time to 3.0 to 1.0, (2) a minimum fixed coverage ratio of 1.15 to 1.0 and (3) a minimum interest coverage ratio of 3.0 to 1.0. At June 30, 2005 and December 31, 2004, Basic was in compliance with its covenants.

Other Debt

        Basic has a variety of other capital leases and notes payable outstanding that are generally customary in its business. None of these debt instruments are material individually or in the aggregate.

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

	Six Months Ended June 30,
	2005		2004
	(Unaudited)
Cash payments for interest	$	5,600	$	3,609
Amortization of debt issuance costs		527		431
Other		74		206
	$	6,201	$	4,246

6.    Commitments and Contingencies

Environmental

        Basic is subject to various federal, state and local environmental laws and regulations that establish standards and requirements for protection of the environment. Basic cannot predict the future impact of such standards and requirements which are subject to change and can have retroactive effectiveness. Basic continues to monitor the status of these laws and regulations. Management believes that the likelihood of the disposition of any of these items resulting in a material adverse impact to Basic's financial position, liquidity, capital resources or future results of operations is remote.

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        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 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 has denied coverage of liability. Basic plans to appeal this verdict. As of June 30, 2005, Basic has accrued a $1.3 million loss, including interest, for this contingency.

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 $100,000, 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 June 30, 2005 and December 31, 2004, self-insured risk accruals, net of related recoveries/receivables totaled approximately $10.6 million and $6.6 million, respectively.

7.    Stockholders' Equity

Common Stock

        In February 2002, a group of related investors purchased a total of 3,000,000 shares of Basic's common stock at a purchase price of $4 per share, for a total purchase price of $12 million. As part of the purchase, 600,000 common stock warrants were issued in connection with this transaction, the fair value of which was approximately $1.2 million (calculated using an option valuation model). The warrants allow the holder to purchase 600,000 shares of Basic's common stock at $4 per share. The warrants are exercisable in whole or in part after June 30, 2002 and prior to February 13, 2007.

        In February 2004, Basic granted certain officers and directors 837,500 restricted shares of common stock. The shares vest 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'

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equity. This amount is being charged to expense over the respective vesting period and totaled approximately $818,000 and $531,000 for the six month periods ended June 30, 2005 and 2004, respectively.

8.    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, 2004) 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 2, 2005 and on May 16, 2005, the board of directors granted various employees options to purchase 865,000 and 5,000 shares, respectively, of common stock of Basic at an exercise price of $6.98 per share. The options vest over a five-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 $5.1 million which is being amortized over the related vesting period.

9.    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 $140,000 for the six months ended June 30, 2004. Basic had no receivables from Southwest Royalties, Inc. as of June 30, 2005 or December 31, 2004.

10.    Employee Benefit Plans

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 $243,000 and $179,000 for the six months ended June 30, 2005 and 2004, respectively.

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

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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 $5,000 for the six months ended June 30, 2005.

11.    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):

		Six months ended June 30,
		2005		2004
		(Unaudited)
Numerator (both basic and diluted):
	Income from continuing operations	$	16,548	$	6,002
	Discontinued operations, net of tax		—		88
	Net income available to common stockholders	$	16,548	$	6,090
Denominator:
	Weighted average common stock outstanding		28,094,435		28,094,435
	Vested restricted stock		312,500		54,515
	Denominator for basic earnings per share		28,406,935		28,148,950
	Stock options		621,937		329,976
	Unvested restricted stock		525,000		529,895
	Common stock warrants		2,921,898		1,838,453
	Denominator for diluted earnings per share		32,475,770		30,847,274
Basic earnings per common share:
	Income from continuing operations less preferred stock dividends and accretion	$	0.58	$	0.21
	Discontinued operations, net of tax		—		0.01
	Net income (loss) available to common stockholders	$	0.58	$	0.22
Diluted earnings per common share:
	Income from continuing operations less preferred stock dividends and accretion	$	0.51	$	0.19
	Discontinued operations, net of tax		—		0.01
	Net income (loss) available to common stockholders	$	0.51	$	0.20

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12.    Discontinued Operations

        In August 2003, Basic's management and board of directors made the decision to dispose of its fluid services operations in Alaska it acquired in the FESCO acquisition prior to closing of the acquisition. After this disposal Basic no longer had any operations in Alaska.

        The following are the results of operations, since their acquisition in October 2003, from the discontinued operations (in thousands):

	Six months ended June 30, 2004
	(Unaudited)
Revenues	$	1,232
Operating costs		(1,090	)
Income taxes — deferred		(54	)
Income from discontinued operations, net of tax	$	88

13.    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's well servicing equipment and capabilities are essential to facilitate most other services performed on a well.

        Fluid Services:    This segment utilizes a fleet of trucks and related assets, including specialized tank trucks, storage tanks, water wells, disposal facilities and related equipment. Basic employs these assets to provide, transport, store and dispose of a variety of fluids. These services are required in most workover, drilling and completion projects as well as part of daily producing well operations.

        Drilling and completion Services:    This segment focuses on a variety of services designed to stimulate oil and gas production or to enable cement slurry to be placed in or circulated within a well. These services are carried out in niche markets for jobs requiring a single truck and lower horsepower.

        Well Site Construction Services:    This segment utilizes a fleet of power units, dozers, trenchers, motor graders, backhoes and other heavy equipment. Basic employs these assets to provide services for the construction and maintenance of oil and gas production infrastructure, such as preparing and maintaining access roads and well locations, installation of small diameter gathering lines and pipelines and construction of temporary foundations to support drilling rigs.

        Basic's management evaluates the performance of its operating segments based on operating revenues and segment profits. Corporate expenses include general corporate expenses associated with managing all reportable operating segments.

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        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):

	Well Servicing			Fluid Services			Drilling and Completion Services			Well Site Construction Services			Corporate and Other		Total
Six months ended June 30, 2005 (Unaudited)
Operating revenues	$	98,650		$	60,839		$	24,276		$	19,866		$	—	$	203,631
Direct operating costs		(61,464	)		(39,119	)		(12,731	)		(14,663	)		—		(127,977	)
Segment profits	$	37,186		$	21,720		$	11,545		$	5,203		$	—	$	75,654
Depreciation and amortization	$	8,727		$	4,691		$	1,193		$	1,324		$	883	$	16,818
Capital expenditures (excluding acquisitions)	$	18,399		$	9,889		$	2,515		$	2,791		$	1,894	$	35,488
Identifiable assets	$	147,956		$	93,141		$	28,569		$	25,012		$	112,232	$	406,910
Six months ended June 30, 2004 (Unaudited)
Operating revenues	$	66,098		$	45,006		$	12,116		$	18,645		$	—	$	141,865
Direct operating costs		(45,416	)		(29,743	)		(7,057	)		(14,384	)		—		(96,600	)
Segment profits	$	20,682		$	15,263		$	5,059		$	4,261		$	—	$	45,265
Depreciation and amortization	$	6,394		$	3,764		$	841		$	1,087		$	692	$	12,778
Capital expenditures (excluding acquisitions)	$	12,417		$	6,674		$	1,697		$	1,883		$	1,257	$	23,928
Identifiable assets	$	114,889		$	68,935		$	6,909		$	37,781		$	90,670	$	319,213

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

	Six Months Ended June 30,
	2005			2004
	(Unaudited)
Segment profits	$	75,654		$	45,265
General and administrative expenses		(26,463	)		(16,780	)
Depreciation and amortization		(16,818	)		(12,778	)
Gain (loss) on disposal of assets		50			(1,863	)
Operating income	$	32,423		$	13,844

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14.    Supplemental Schedule of Non-Cash Investing and Financing Activities

	Six Months Ended June 30,
	2005		2004
	(In thousands, Unaudited)
Capital leases issued for equipment	$	3,580	$	4,373
Interest rate swap	$	468	$	245
Deferred compensation	$	5,504	$	6,259
Common stock issued in business acquisition	$	—	$	2,874
Forfeiture of restricted stock	$	79	$	—

15.    Subsequent Events

Stock Split

        On August 3, 2005, the board of directors of Basic approved a resolution to effect a 5-for-1 stock split of its common stock in the form of a stock dividend resulting in 28,931,935 shares of common stock outstanding, and to amend its 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.

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Report of Independent Auditors

To the Board of Directors and Stockholders of
FESCO Holdings, Inc. and Subsidiaries:

        In our opinion, the accompanying consolidated balance sheet as of December 31, 2002 and the related consolidated statements of operations, stockholders' equity and cash flows present fairly, in all material respects, the financial position of FESCO Holdings, Inc. and Subsidiaries at December 31, 2002 and the results of their operations and their cash flows for the year then ended in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit of these statements in accordance with auditing standards generally accepted in the United States of America, which 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, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion. The financial statements of FESCO Holdings, Inc. and subsidiaries as of December 31, 2001 and 2002 and for each of the two years in the period ended December 31, 2001, were audited by other independent accountants who have ceased operations. Those independent accountants expressed an unqualified opinion on those financial statements in their report dated March 7, 2002.

/s/ PricewaterhouseCoopers LLP

Denver, Colorado
March 7, 2003, except with respect to the matter discussed in Note 11, for which the date is August 28, 2003.

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FESCO Holdings, Inc. and Subsidiaries

Consolidated Balance Sheet

as of December 31, 2002

Assets
Current Assets
	Cash and cash equivalents		$	4,651,460
	Trade accounts receivable, net of allowance for doubtful accounts of $122,392			9,341,988
	Other receivables			37,209
	Income taxes receivable			1,320,508
	Inventories			736,658
	Prepaid expenses and other current assets			389,995
		Total current assets		16,477,818
Property, plant and equipment, net				40,778,656
Intangible assets, net				4,616,056
Goodwill, net				9,299,013
Other assets				1,063,510
		Total assets	$	72,235,053
Liabilities and Stockholders' Equity
Current Liabilities
	Accounts payable		$	1,638,559
	Accrued payroll			782,392
	Other accrued liabilities			1,566,078
	Current portion of accrued earn out payment			897,177
	Current portion of long-term debt			3,245,900
	Current portion of capital lease obligations			1,264,688
		Total current liabilities		9,394,794
Long-term debt, net of current portion				13,573,671
Capital lease obligations, net of current portion				2,634,765
Accrued earn out payment, net of current portion				358,333
Other long-term liabilities				40,000
Deferred income taxes				7,779,010
		Total liabilities		33,780,573
Commitments and contingencies (Note 9)
Stockholders' Equity
	Preferred stock, $.01 par value; 500,000 authorized shares; no shares issued and outstanding as of December 31, 2002
	Common stock, $0.001 par value; 500,000 authorized shares; 406,607 issued and outstanding shares as of December 31, 2002			406
	Additional paid-in capital			40,660,294
	Retained deficit			(2,206,220	)
		Total stockholders' equity		38,454,480
		Total liabilities and stockholders' equity	$	72,235,053

The accompanying notes are an integral part of these consolidated financial statements.

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FESCO Holdings, Inc. and Subsidiaries

Consolidated Statement of Operations

Year Ended December 31, 2002

		Year Ended December 31, 2002
Sales		$	51,292,683
Cost of Sales			46,385,810
Rents paid to related parties			49,920
Gross Profit			4,856,953
Operating Expenses
	Selling, general and administrative		6,497,859
	Amortization of intangibles		974,398
	Loss on sale of assets		1,544,570
	Bad debt expense		121,110
Operating Loss			(4,280,984	)
	Interest expense		(1,610,479	)
	Interest income		78,113
	Other expenses		18,377
Loss before provision for income taxes			(5,831,727	)
	Benefit for income taxes		1,990,593
Net loss		$	(3,841,134	)

The accompanying notes are an integral part of these consolidated financial statements.

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FESCO Holdings, Inc. and Subsidiaries

Consolidated Statement of Stockholders' Equity

For the Year Ending December 31, 2002

	Common Stock
				Additional Paid-in Capital		Retained Earnings (Deficit)
	Shares	Amount							Total
Balances at December 31, 2001	273,295	$	273	$	27,329,227	$	1,634,914		$	28,964,414
Issuance of common stock to Fund VIII for cash Investment, March 20, 2002	130,000		130		12,999,870		—			13,000,000
Issuance of common stock to former Schmid Shareholders for the settlement of deferred purchase price payments, November 6, 2002	3,312		3		331,197		—			331,200
Net loss	—		—		—		(3,841,134	)		(3,841,134	)
Balances at December 31, 2002	406,607	$	406	$	40,660,294	$	(2,206,220	)	$	38,454,480

The accompanying notes are an integral part of these consolidated financial statements.

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FESCO Holdings, Inc. and Subsidiaries

Consolidated Statement of Cash Flows

				Year Ended December 31, 2002
Cash flows from Operating Activities
	Net loss			$	(3,841,134	)
	Adjustments to reconcile net loss to net cash provided by operating activities
		Depreciation and amortization			8,276,808
		Loss on sale of assets			1,544,570
		Deferred income taxes			(896,390	)
		Amortization of deferred loan fees			230,872
		Changes in other non-current assets			59,379
	Changes in current assets and liabilities
		Receivables			987,357
		Inventories			(126,027	)
		Other current assets			45,387
		Accounts payable and accrued liabilities			(1,405,963	)
		Income taxes receivable			(471,677	)
			Net cash provided by operating activities		4,403,182
Cash flows from Investing Activities
	Purchases of property, plant and equipment				(3,607,843	)
	Proceeds from sale of property, plant and equipment				1,205,709
	Schmid acquisition earn-out payment				(1,376,008	)
			Net cash used in investing activities		(3,778,142	)
Cash flows from Financing Activities
	Proceeds from note payable to Fund VIII				13,000,000
	Proceeds from issuance of equipment notes payable				1,200,913
	Repayment of long-term debt				(11,085,380	)
	Repayment of capital lease obligations				(1,765,399	)
	Repayment of lines of credit				(290,681	)
			Net cash provided by financing activities		1,059,453
Net increase in cash and cash equivalents					1,684,493
Cash and cash equivalents, beginning of period					2,966,967
Cash and cash equivalents, end of period				$	4,651,460
Supplemental Cash Flow Information
	Cash paid during the year for:
		Interest		$	1,686,528
		Taxes		$	—
Supplemental Disclosure of Non-Cash Investing and Financing Activities
		Common stock issued for the earn-out of Schmid		$	331,200
		Note payable to Fund VIII converted to common stock		$	13,000,000
		Property acquired through the buy-out of operating leases		$	211,560
		Equipment notes and capital lease obligations refinanced		$	5,462,855
		Accrued Schmid earn-out payment		$	1,255,510

The accompanying notes are an integral part of these consoliated financial statements.

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FESCO Holdings, Inc. and Subsidiaries

Notes to Consolidated Financial Statements

December 31, 2002

1.    Organization and Business Activity

        First Energy Services Company ("FESCO" or the "Company") was incorporated under the laws of the State of Delaware on April 19, 2000 ("Inception") to acquire and manage oil and gas well site service providers. The Company commenced substantial operations on June 16, 2000 upon the acquisition of Schmid Oilfield Services, Inc. ("Schmid"), and subsequently completed several other acquisitions. The Company's operations are conducted entirely in the United States.

        As noted above, on June 16, 2000, the Company acquired 100% of the outstanding common shares of Schmid. Schmid is a provider of oil field construction and maintenance support services in the mineral, chemical, utility and petroleum industries of the Green River and Powder River Basins of Wyoming.

        On July 1, 2000, the Company acquired 100% of the outstanding common shares of Gane Production Services, Inc. ("Gane"). Gane is a provider of oil and gas maintenance and construction services in the Powder River Basin of Wyoming. The acquisition was accounted for under the purchase method of accounting and, accordingly, the assets, liabilities and operating results of Gane have been included in the accompanying consolidated financial statements from July 1, 2000.

        On July 1, 2000, the Company acquired 100% of the outstanding common shares of Busha Enterprises, Inc. ("Busha"). Busha is a provider of fluid hauling services to the oil and gas industry in the DJ and Piceance Basins of Colorado. The acquisition was accounted for under the purchase method of accounting and, accordingly, the assets, liabilities and operating results of Busha have been included in the accompanying consolidated financial statements from July 1, 2000.

        Effective July 1, 2000, the Company acquired certain assets and liabilities of Sun Cementing of Wyoming, Inc. ("Sun"). The assets acquired are used in the operation of the cementing business in Gillette, Wyoming. This transaction was accounted for under the purchase method of accounting.

        On August 30, 2002, the Company restructured the organization to better-align the above acquisitions into geographic regions. All wholly owned subsidiaries, except HB&R (Note 3), were merged with and into the Company. Operations were divided into specific geographic regions and began operating under the First Energy name. In connection with the restructuring, a new holding company, FESCO Holdings, Inc. ("Holdings"), was incorporated in the state of Delaware to acquire all of the outstanding shares of FESCO.

2.    Significant Accounting Policies

Principles of Consolidation

        The consolidated financial statements include the accounts of Holdings and its wholly-owned subsidiaries for the period, subsequent to acquisition. All significant intercompany accounts, profits and transactions have been eliminated in consolidation.

Use of Estimates

        The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at

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the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Cash and Cash Equivalents

        Cash and cash equivalents consist of highly liquid investments with original maturities of three months or less. The Company places its temporary cash investments in financial institutions that management believes to be of high credit quality. As such, the Company believes no significant concentration of credit risk exists with respect to these investments.

Accounts receivable

        Accounts receivable are recorded at cost, net of allowance for doubtful accounts. The Company evaluates the collectibility of its accounts receivable based on the specific identification of problem accounts. In circumstances where the Company is aware of a specific customer's inability to meet its financial obligations, it records a specific reserve to reduce receivables to what it believes will be collected. The allowance for doubtful accounts is reconciled as follows for the year ended December 31, 2002:

Allowance for doubtful accounts — Beginning Balance	$	10,590
Provision for bad debt expense		121,110
Write-offs		(9,308	)
Allowance for doubtful account — ending balance	$	122,392

Inventories

        Inventories consist of gravel, fuel, spare parts and supplies used to operate and maintain the Company's vehicles and equipment. Inventories are carried at the lower of cost or market utilizing the first-in, first-out method. The Company's inventory was comprised of the following at December 31, 2002:

Gravel	$	452,325
Spare parts and supplies		284,333
	$	736,658

Fair Value of Financial Instruments

        The carrying amounts reported in the accompanying consolidated balance sheets for cash and cash equivalents, trade accounts receivable, accounts payable and accrued liabilities approximate fair value due to the short-term maturities of these instruments. The carrying amounts reported in the accompanying consolidated balance sheets for the line of credit, long-term debt and capital lease obligations approximate fair value since the applicable interest rates are either variable or representative of rates obtainable by the Company on December 31, 2002.

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Property, Plant and Equipment

        Property and equipment are stated at cost and are depreciated on a straight-line basis over the estimated useful lives of the assets as noted below.

Asset	Estimated Useful Lives
Land	Not depreciated
Buildings and improvements	15 to 40 years
Vehicles and equipment	5 to 8 years
Furniture and fixtures	3 to 5 years
Leased equipment	Term of corresponding lease

        Maintenance and repairs are expensed as incurred. Betterments, major capital improvements and rebuilds that extend the useful life of the property, plant and equipment are capitalized.

Intangibles Assets

        The Company classifies intangible assets as definite-lived intangible assets or goodwill. Definite-lived intangibles include primarily employment agreements, non-compete agreements and customer relationships. The Company periodically reviews the appropriateness of the amortization periods related to its definite-lived assets. These assets are stated at cost. Intangible assets are being amortized on a straight-line basis over the estimated useful lives of the assets as noted below. Amounts paid out under earn out arrangements from acquisitions are capitalized when the amounts can be determined with certainty.

Intangible Asset	Estimated Useful Lives
Employment agreements	1 to 3 years
Non-compete agreements	3 years
Customer lists	10 years

Goodwill

        Goodwill represents the excess of cost over the fair value of tangible assets and identified intangible assets acquired in the acquisitions described in Note 1. Prior to the adoption of Statement of Financial Accounting Standards No. 142, "Goodwill and Other Intangible Assets" ("SFAS 142") on January 1, 2002, the Company amortized goodwill over an estimated useful life of 10 years. Beginning in fiscal 2002, in connection with the adoption of SFAS 142, the Company no longer amortizes goodwill. Goodwill is evaluated at least annually for impairment in accordance with the provisions of SFAS 142.

Impairment of Assets

        Long-lived assets and intangible assets are reviewed for impairment in accordance with the provisions of Statement of Financial Accounting Standards No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" ("SFAS 144"), whenever changes in events or circumstances indicate the carrying amount of these assets may not be recoverable. If this review indicates that

F2-8

the carrying value of these assets will not be recoverable, based on future undiscounted net cash flows from the use or disposition of the assets, the carrying value is reduced to estimated fair value.

Income Taxes

        The current provision for income taxes represents estimated amounts due on tax returns filed or to be filed. Deferred tax assets and liabilities are recorded for the estimated future tax effects of temporary differences between the tax basis of assets and liabilities and amounts reported in the consolidated balance sheets. The overall change in deferred tax assets and liabilities for the period, exclusive of deferred tax assets and liabilities recorded in purchase accounting for businesses acquired, measures the deferred tax expense or benefit for the period. Effects of changes in enacted tax laws on deferred tax assets and liabilities are reflected as adjustments to tax expense in the period of enactment.

Concentration of Credit Risk

        The Company's trade accounts receivable are concentrated with certain customers in the oil and gas industry. Although diversified among many companies, collectibility is dependent upon general economic conditions of the oil and gas industry in the regions in which the Company operates. During the year ended December 31, 2002, virtually all of the Company's revenue came from oil and gas industry customers, with two significant customers contributing 33% of the Company's revenue.

Revenue and Cost Recognition

        Revenues from time-and-material contracts are recognized currently as the work is performed. Costs include all direct material and labor costs and those indirect costs related to contract performance, such as indirect labor, supplies, tools, repairs, and depreciation costs.

New Accounting Pronouncements

        During June 2001, the FASB issued Statement of Financial Accounting Standards No. 143, "Accounting for Asset Retirement Obligations" ("SFAS 143"). SFAS 143 establishes accounting standards for recognition and measurement of a liability for an asset retirement obligation and the associated asset retirement cost. SFAS 143 requires an entity to recognize the fair value of a liability for an asset retirement obligation in the period in which it is incurred if a reasonable estimate can be made. The Company is required to adopt SFAS 143 on January 1, 2003. The adoption of SFAS 143 is not expected to have a significant impact on the Company.

        In April 2002, the FASB issued 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 ("FAS 145"). This Statement rescinds FASB Statement No. 4, Reporting Gains and Losses from Extinguishment of Debt, and an amendment of that statement, FASB Statement No. 64, Extinguishments of Debt Made to Satisfy Sinking-Fund Requirements. This statement amends FASB Statement No. 13, Accounting for Leases, to eliminate an inconsistency between the required accounting for sale-leaseback transactions and the required accounting for certain lease

F2-9

modifications that have economic effects that are similar to the sale-leaseback transactions. FAS 145 is effective for the Company for fiscal year 2002. The adoption of FAS 145 did not have a significant effect on the Company's results of operations or its financial position.

        In June 2002, the FASB issued Statement of Financial Accounting Standards No. 146, Accounting for Costs Associated with Exit or Disposal Activities ("FAS 146"). This statement requires costs associated with exit or disposal activities, such as lease termination or employee severance costs, to be recognized when they are incurred rather than at the date of a commitment to an exit or disposal plan. FAS 146 replaces Emerging Issues Task Force Issue No. 94-3, "Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring)," which previously provided guidance on this topic. FAS 146 is to be applied prospectively to exit or disposal activities initiated after December 31, 2002. Management believes that the adoption of FAS 146 will not have a significant effect on the Company's results of operations or its financial position.

        In November 2002, the FASB issued FASB Interpretation no. 45 ("FIN 45"), "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others." FIN 45 requires that a liability be recorded in the guarantor's balance sheet upon issuance of a guarantee. In addition, FIN 45 requires disclosures about the guarantees that an entity has issued. As FESCO has not entered into such guarantee agreements, the adoption of FIN 45 is not expected to have a significant effect on the Company's results of operations or its financial statements.

        In December 2002, the FASB issued Statement of Financial Accounting Standards No. 148, Accounting for Stock-Based Compensation — Transition and Disclosure — An Amendment to FASB Statement No. 123 ("FAS 148"). This statement amends FAS 123, to provide alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation. In addition, FAS 148 amends the disclosure requirements of FAS 123 to require prominent disclosures in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on reported results. The adoption of FAS 148 is not expected to have a significant effect on the Company's results of operations or its financial position.

        In January 2003, the FASB issued FASB Interpretation no. 46 ("FIN 46"), "Consolidation of Variable Interest Entities, an Interpretation of ARB No. 51." FIN 46 requires certain variable interest entities ("VIEs") to be consolidated by the primary beneficiary of the entity if the equity investors in the entity do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support from other parties. FIN 46 is effective for all new VIEs created or acquired after January 31, 2003. For VIEs created or acquired prior to February 1, 2003, the provisions of FIN 46 must be applied for the first interim or annual period beginning after June 15, 2003. The adoption of this standard is not expected to have a significant effect on FESCO's financial statements.

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3.    Acquisition Earn-Out payments

        In accordance with the original terms of the Schmid acquisition agreement, additional cash consideration in the form of an earn-out payment was required to be paid to the former shareholders of Schmid in 2002. The earn-out payment was to be based upon the amount of EBITDA, as defined, earned by Schmid for the two-year period ending March 31, 2002, plus accrued interest from March 31, 2001 to March 31, 2002 at a rate equal to the prime interest rate plus 1.0%.

        In November 2001, a portion of the earn-out payment was paid through the issuance of 9,307 shares of the Company's common stock, valued at $930,700.

        In November 2002, the Company and the former shareholders of Schmid agreed upon the amount and terms of the remaining unpaid earn-out payment in a negotiated settlement agreement. In settlement of the earn-out payment, the Company agreed to pay the former Schmid shareholders a total of $2,575,000, plus accrued interest from March 31, 2001 to the final payment date, at a rate of 6.5% per annum. The Company paid $1,200,000 in cash and $300,000 in stock, plus accrued interest of $124,900 and $31,200 in cash and stock, respectively, on November 6, 2002. In addition, the Company has accrued $1,075,000 in additional earn-out payments plus $180,500 in accrued interest as of December 31, 2002. The remaining accrued earn-out payment will be paid in equal installments of $358,333 on January 1, 2003, October 1, 2003 and October 1, 2004.

        The total earn-out payment of $2,575,000, interest of $336,700 and legal costs of $51,000 associated with the Schmid earn-out payment was recorded as additional goodwill in the Schmid acquisition during 2002.

4.    Property, Plant and Equipment

	December 31, 2002
Land	$	389,056
Buildings and improvements		2,672,052
Vehicles and equipment		49,823,452
Furniture and fixtures		608,431
		53,492,991
Less: Accumulated depreciation		(13,049,650	)
Construction in progress		335,315
	$	40,778,656

        Depreciation expense amounted to $7,302,412 for the year ended December 31, 2002. As of December 31, 2002, the Company capitalized leases of vehicles and equipment with historical costs of $7,124,588 and accumulated amortization of $1,598,295.

F2-11

5.    Intangible Assets and Goodwill

		December 31, 2002
Intangible assets
	Employment agreements (net of accumulated amortization of $190,954)	$	59,046
	Non-compete agreements (net of accumulated amortization of $607,190)		232,810
	Customer lists (net of accumulated amortization of $4,324,201)		4,324,200
		$	4,616,056

        The Company recognized $974,396 in amortization expense during the year ended December 31, 2002. Estimated future amortization expense related to purchased intangible assets at December 31, 2002 is as follows:

Twelve Months Ending December 31,
	2003	$	778,290
	2004		569,767
	2005		528,100
	2006		528,100
	2007		528,100
	Thereafter		1,683,699
		$	4,616,056

        The following schedule shows development of goodwill balance during fiscal year 2002:

Balance, January 1, 2002		$	6,999,781
Additions
	Schmid earn-out payment (including interest and other costs)		2,962,718
Balance, December 31, 2002			9,962,499
Less: Accumulated amortization			(663,486	)
Goodwill, net		$	9,299,013

F2-12

6.    Long-Term Debt and Capital Lease Obligations

Long-Term Debt

        A summary of the Company's notes payable as of December 31, 2002 is as follows:

GE Capital Term Loan	$	11,812,500
Equipment notes payable		5,007,071
		16,819,571
Less: Current portion		(3,245,900	)
	$	13,573,671

        On August 30, 2001, the Company and certain of its subsidiaries entered into a credit agreement (the "Agreement") with General Electric Capital Corporation ("GE Capital") to refinance certain equipment notes payable assumed through the acquisition of the Company's subsidiaries and the funds borrowed from the Company's majority shareholder, First Reserve Fund VIII L.P. ("Fund VIII"). The Agreement allows for borrowings up to an aggregate sum of $30,000,000, consisting of a Revolving Credit Facility, a Term Loan, an Acquisition Term Loan, a Swing Line Facility and Letters of Credit. All borrowings under the Agreement bear interest at variable interest rates as explained below. The Agreement calls for mandatory prepayments equal to the proceeds from the sale of fixed assets, the proceeds in excess of $250,000 from the sale of Company common stock, and Excess Cash Flow, as defined, beginning in the year ending December 31, 2002. The Agreement is guaranteed by the Company and is secured by all of the Company's personal and real property not already collateralized by other notes and leases. Loan origination fees of $1,073,392 were incurred in connection with the Agreement. These fees are included in other assets in the accompanying consolidated balance sheets and are being amortized to interest expense over the terms of the related loans. A commitment fee of 0.5% of the average remaining available borrowings is due monthly.

        Borrowings under the Revolving Credit Facility may be repaid at any time without penalty but must be repaid in full by August 30, 2006; may not exceed $7,500,000; bear interest at either a) the Index Rate, as defined, plus 1.75% (6.0% as of December 31, 2002), or b) the Company may commit a portion of the outstanding borrowings under the Revolving Credit Facility to one, two or three month terms bearing interest at the LIBOR Rate, as defined, plus 3.25% (5.01%% as of December 31, 2002). The Company is required to pay a monthly commitment fee equal to 0.50% of the remaining funds available under the Revolving Credit Facility. There were no amounts outstanding and $7,500,000 available for borrowing on the Revolving Credit Facility as of December 31, 2002.

        The Term Loan bears interest at the Company's option of either a) the Index Rate, as defined, plus 2.00% (6.25% as of December 31, 2002) or b) the LIBOR Rate plus 3.50% (5.26% as of December 31, 2002). Commencing December 31, 2001, accrued interest computed on the outstanding Term Loan balance is due monthly and principal repayments of $437,500 are due quarterly with the remaining principal balance due at August 30, 2006. The Term Loan may be prepaid at any time in the minimum amount of $500,000. There was $11,812,500 outstanding and $2,187,500 avaiable for borrowing on the Term Loan as of December 31, 2002.

F2-13

        The Acquisition Term Loan bears interest at either a) the Index Rate, as defined, plus 2.00 (6.25% as of December 31, 2002) or b) the Company may commit a portion of the outstanding borrowings under the Acquisition Term Loan to one, two or three month terms bearing interest at the LIBOR Rate, as defined, plus 3.50% (5.26% as of December 31, 2002). Commencing December 31, 2001, accrued interest computed on the outstanding Acquisition Term Loan balance is due monthly and principal repayments of $266,625 are due quarterly with the remaining principal balance due at August 30, 2006. The Acquisition Term Loan was paid off on March 19, 2002. There were no amounts outstanding and $8,500,000 available for borrowing on the Acquisition Term Loan as of December 31, 2002.

        To the extent that the Company's Borrowing Base, as defined, exceeds that used to determine the initial $30,000,000 credit limit under the Agreement, additional funds will be available to the Company by utilizing the Swing Line Facility. As of December 31, 2002, the Company had no available borrowings under the Swing Line Facility. The Borrowing Base as of December 31, 2002 was $7,199,683.The Company may request Letters of Credit from time to time from GE Capital in an amount not to exceed the lesser of $1,000,000 or the funds remaining under the Revolving Credit Facility. Outstanding Letters of Credit bear a fee equal to 3.25% of the outstanding amount. The Company had no Letters of Credit outstanding as of or during the year ended December 31, 2002.

        Aggregate indebtedness to GE Capital under the Revolving Credit Facility, Term Loan and Acquisition Term Loan as of December 31, 2002 was $11,812,500, of which substantially the balance bears interest at the LIBOR Rate plus 3.5%. The weighted average interest rate for the period these borrowings were outstanding in 2002 was 5.38%. For the year ended December 31, 2002, total interest expense related to these borrowings was $932,468.

        On August 30, 2002, the Company amended the Agreement ("Amendment") in conjunction with the reorganization discussed in Note 1. The Amendment established the Company as the primary borrower under the Agreement, and removed the Company's subsidiaries as borrowers under the Agreement. No other material changes were made.

        The Agreement is subject to various financial and non-financial covenants. GE Capital has the option to call the debt in the event of noncompliance with these covenants.

        On March 9, 2002, the Company entered into a Note Payable with Fund VIII and received proceeds of $13,000,000. The Note Payable was subsequently converted to equity of the Company through the issuance of 130,000 shares of the Company's common stock.

        The Company has entered into various notes for the purchase of equipment and vehicles bearing interest at rates ranging from 0.0% to 8.75% per annum which mature at various dates from May 2003 to January 2007. These notes are collateralized by the related equipment and vehicles which have a net book value of $5,647,953 at December 31, 2002.

F2-14

        At December 31, 2002, aggregate scheduled maturities of long-term debt are as follows:

		GE Capital		Equipment Notes		Total
Year ending December 31:
	2003	$	1,750,000	$	1,495,900	$	3,245,900
	2004		1,750,000		1,447,199		3,197,199
	2005		1,750,000		1,304,952		3,054,952
	2006		6,562,500		755,891		7,318,391
	2007		—		3,129		3,129
	Total	$	11,812,500	$	5,007,071	$	16,819,571

Capital Lease Obligations

        The Company has entered into a capital lease obligation for equipment and vehicles. The obligation bears interest at 5.75% per annum and matures January 2006. The lease obligation is collateralized by the related equipment and vehicles which have a net book value of approximately $5,526,293 at December 31, 2002.

        At December 31, 2002, future minimum payments required under capital lease obligation follows:

Year ending December 31:
	2003	$	1,455,573
	2004		1,382,851
	2005		1,310,131
	2006		105,894
			4,254,449
	Less: Interest		(354,996	)
Future minimum principal payments			3,899,453
Less: Current portion			(1,264,688	)
Long-term portion of capital lease obligations		$	2,634,765

7.    Stockholders' Equity

Common and Preferred Stock

        The Company is authorized to issue 500,000 shares of $0.001 par value common stock and 500,000 shares of $.01 par value preferred stock. The rights, terms and conditions of the preferred shares will be determined by the board of directors prior to issuance of any series of preferred stock.

F2-15

Restricted Shares

        The Company's stock may not be transferred without the consent of the Company. Upon consent by the Company of any share transfers, Fund VIII has a right of first refusal to purchase such shares from the selling shareholder based upon the then fair value of the shares. Furthermore, if greater than 50% of the Company's fully diluted common stock is transferred, any remaining shareholders will be required to transfer their shares to the acquirer.

Stock Options

        The Company's 2000 Stock Option Plan (the "2000 Plan"), provides for the grant of options to purchase up to an aggregate of 21,053 shares of common stock of FESCO by employees and nonemployees; of which 8,990 shares are available for grant as of December 31, 2002. The exercise price of nonqualified options granted is determined by the Board of Directors based on the estimated fair market value of FESCO common stock at the date of grant. The 2000 Plan allows for option awards to be granted for ten years from the effective date of the plan, which was June 16, 2000, and options granted have a term of ten years. Options vest as determined by the Board. Since inception, the Board has issued time and performance awards. Time awards vest over four years, with one-fourth vesting at the end of each year. Performance awards vest based on a formula which will not be computed until the date of a Liquidity Event, as defined. Since the number of shares which will be exercisable is not fixed, the performance awards are accounted for under variable accounting and stock-based compensation expense may be recorded in the future when it is probable the shares under grant will become exercisable. The amount of compensation per share will be the difference between the fair value per share of common stock minus the exercise price. If employment is terminated for any reason, vested options must be exercised within 90 days of termination or they are automatically canceled.

        In 2002, the Company cancelled 7,100 options and granted 2,600 options to employees with an exercise price of $100 per share and weighted average fair value of $17.08 per option. As of December 31, 2002, there are 8,990 options outstanding, of which 1,017 are exercisable. These options have an estimated remaining contractual life of 9.1 years. No options have been granted to non-employees.

Fair Value Disclosures

        The Company calculated the minimum fair value of each option grant on the date of grant using the minimum value method utilizing Black-Scholes option pricing model as prescribed by SFAS No. 123 using the following assumptions during the year ended December 31, 2002.

Weighted average risk-free interest rate	4.16	%
Expected lives, in years	4.5
Dividend yield	N/A

        The pro forma compensation cost associated with the Company's stock-based compensation plans, determined using the minimum value method prescribed by SFAS No. 123, results in a pro

F2-16

forma charge of approximately $23,600 to the reported net income during the year ended December 31, 2002.

8.    Income Taxes

        The benefit for income taxes consists of the following:

			Year Ended December 31, 2002
Current
	Federal		$	(1,094,203	)
	State			—
Current benefit				(1,094,203	)
Deferred
	Federal			(789,471	)
	State			(106,919	)
Deferred benefit				(896,390	)
		Total	$	(1,990,593	)

        The following is a reconciliation of the difference between the actual benefit for income taxes and the benefit computed by applying the federal statutory rate of 34% to income before income taxes for the year ended December 31, 2002:

Benefit at statutory rate	$	(1,982,787	)
Non-deductible items		20,393
Alternative minimum tax credit		(79,860	)
State taxes and other		(162,605	)
Other adjustments		214,266
	$	(1,990,593	)

        Net deferred tax liabilities are recognized for the future tax consequences of differences between the carrying amounts of assets and liabilities and their respective tax bases using enacted tax rates in effect for the year in which the differences are expected to reverse. The net deferred tax liability consists of differences in amortization rates between book and tax depreciation and amortization of intangible assets and property, plant and equipment.

F2-17

        The net deferred tax liability is comprised of the tax effect of the difference between the book and tax assets of the following at December 31, 2002:

Deferred tax assets:
	Accounts receivable		$	30,892
	Accrued liabilities			254,672
	Net operating loss carryforwards			630,089
	AMT credits			35,523
	Other			49,221
		Total deferred tax assets		1,000,397
Deferred tax liabilities:
	Property, plant and equipment			(7,201,292	)
	Intangible assets			(1,436,251	)
	Other			(141,864	)
		Total deferred tax liabilities		(8,779,407	)
Net deferred tax liabilities			$	(7,779,010	)

        At December 31, 2002, the Company had federal net operating loss carryforwards of approximately $1,570,290, which begin to expire in 2022, and are available to offset future taxable income. Realization of the deferred tax assets is dependent upon generating sufficient taxable income prior to expiration of any net operating loss carryforwards. Although realization is not assured, management believes that a valuation allowance is not required for its domestic deferred tax assets as it is more likely that not the Company will be able to realize the benefit of the net operating loss carryforward through the reversal of existing taxable temporary differences.

        Prior to the acquisition of Gane, this subsidiary filed with the Internal Revenue Service as a subchapter S Corporation. Although the Company is a subchapter C Corporation, the ownership of this subsidiary could expose the Company to liabilities from this subsidiary's previous tax activity if their subchapter S Corporation status were denied by the Internal Revenue Service for any period prior to the Company's acquisition of this subsidiary.

F2-18

9.    Commitments and Contingencies

Operating Lease Commitments

        The Company has entered into noncancelable operating leases for equipment and real property with lease terms through 2007. Future minimum lease payments at December 31, 2002 are as follows:

Year ending December 31,
	2003		$	303,174
	2004			211,085
	2005			372,088
	2006			8,400
	2007			3,500
		Total minimum payments	$	898,247

        Rental expense for the year ended December 31, 2002 for operating leases was $635,225.

Employee Retirement Plans

        The Company provides voluntary 401(k) employee savings plans covering all eligible employees of its Schmid, Sun and HB&R subsidiaries (the "401(k) Plans"). Participants in the 401(k) Plans may contribute up to 20% of their eligible compensation. Qualified and non-qualified, discretionary employer contributions may be made by the Company which are allocated to eligible employees based upon their representative share of total compensation paid to eligible employees during the year. Participant and qualified employer contributions vest immediately, whereas non-qualified employer contributions vest ratably until the participant reaches their sixth year of service. During the year ended December 31, 2002, the Company contributed $157,917 to the 401(k) Plans.

10.    Related Parties

        As discussed in Note 3, the Company accrued $1,255,500 for its earn-out obligation and accrued interest to the former Schmid shareholders.

        The Company leases various land and buildings from entities owned by the former owners of Busha and Gane under the operating leases described above. Total rental payments to the entities owned by the former owners of Busha and Gane related to these leases were $49,920, and the monthly rental payments to these entities were $4,160 for the year ended December 31, 2002.

        Both the former Schmid and Busha shareholders are shareholders of FESCO.

11.    Subsequent Event

        On August 28, 2003, the Company executed a waiver and amendment to the Agreement with GE Capital (as described in Note 7) to cure certain defaults at December 31, 2002, and to loosen certain financial covenant requirements for fiscal 2003 that would have otherwise resulted in a default status.

F2-19

This report is a copy of the previously issued report covering fiscal years 2001 and 2000. This report has not been reissued by Arthur Andersen LLP in connection with this filing nor has Arthur Andersen LLP provided a consent to the inclusion of its report in this prospectus.

REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

To the Board of Directors and Stockholders of
First Energy Services Company:

        We have audited the accompanying consolidated balance sheets of FIRST ENERGY SERVICES COMPANY (a Delaware corporation) and subsidiaries as of December 31, 2001 and 2000, and the related consolidated statements of income, stockholders' equity and cash flows for the year ended December 31, 2001 and for the period from inception (April 19, 2000) to December 31, 2000. These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

        We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the consolidated 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 First Energy Services Company and subsidiaries as of December 31, 2001 and 2000, and the results of their operations and their cash flows for the year ended December 31, 2001 and for the period from inception (April 19, 2000) to December 31, 2000 in conformity with accounting principles generally accepted in the United States.

/s/ Arthur Andersen

Denver, Colorado
March 7, 2002

F2-20

FIRST ENERGY SERVICES COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

AS OF DECEMBER 31, 2001 AND 2000

			2001		2000
ASSETS
CURRENT ASSETS:
	Cash and cash equivalents		$	2,966,967	$	3,220,851
	Trade accounts receivable, net of allowance for doubtful accounts of $10,590 and $2,600, respectively			10,068,223		4,480,229
	Other receivables			298,331		144,903
	Income taxes receivable			848,831		—
	Inventories			610,631		106,817
	Prepaid expenses and other current assets			435,382		410,512
		Total current assets		15,228,365		8,363,312
PROPERTY, PLANT AND EQUIPMENT, net				47,223,504		14,023,975
INTANGIBLE ASSETS, net				5,590,452		2,548,702
GOODWILL, net				6,336,295		1,592,205
OTHER ASSETS				1,353,761		106,731
Total assets			$	75,732,377	$	26,634,925
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
	Accounts payable		$	2,523,009	$	1,737,413
	Accrued liabilities			2,869,983		764,556
	Income taxes payable			—		579,719
	Current portion of line of credit			290,681		35,559
	Current portion of equipment notes payable			3,870,877		957,414
	Current portion of captial lease obligations			1,493,165		596,900
		Total current liabilities		11,047,715		4,671,561
LINE OF CREDIT, net of current portion				—		9,391
NOTES PAYABLE, net of current portion				22,833,161		1,931,361
CAPITAL LEASE OBLIGATIONS, net of current portion				4,171,687		765,611
OTHER LONG TERM LIABILITIES				40,000		—
NOTE PAYABLE TO FIRST RESERVE FUND VIII L.P.				—		7,793,850
DEFERRED INCOME TAXES				8,675,400		2,364,617
Total liabilities				46,767,963		17,536,391
COMMITMENTS AND CONTINGENCIES (Note 9)
STOCKHOLDERS' EQUITY:
	Preferred stock, $.01 par value; 500,000 aurthorized shares; no shares issued and outstanding as of December 31, 2001 and 2000
	Common stock, $0.001 par value; 500,000 authorized shares; 273,295 and 83,938 issued and outstanding shares as of December 31, 2001 and 2000, respectively			273		84
	Additional paid-in capital			27,329,227		8,393,716
	Retained earnings			1,634,914		704,734
		Total stockholders' equity		28,964,414		9,098,534
		Total liabilities and stockholders' equity	$	75,732,377	$	26,634,925

The accompanying notes are an integral part of these consolidated balance sheets.

F2-21

FIRST ENERGY SERVICES COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

		Year Ended December 31, 2001			Period From Inception (April 19, 2000) To December 31, 2000
SALES		$	54,343,406		$	14,246,506
COST OF SALES			39,509,716			9,260,461
GROSS PROFIT			14,833,690			4,986,045
OPERATING EXPENSES:
	Selling, general and administrative		9,209,768			2,730,320
	Amortization of intangibles		1,470,861			420,156
OPERATING INCOME			4,153,061			1,835,569
	Interest expense		(2,427,833	)		(614,857	)
	Interest income		119,993			59,124
	Other expenses		(113,198	)		(7,102	)
INCOME BEFORE PROVISION FOR INCOME TAXES			1,732,023			1,272,734
	Provision for income taxes		801,843			568,000
NET INCOME		$	930,180		$	704,734

The accompanying notes are an integral part of these consolidated statements.

F2-22

FIRST ENERGY SERVICES COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY

FOR THE YEAR ENDED DECEMBER 31, 2001 AND FOR

THE PERIOD FROM INCEPTION (APRIL 19, 2000) TO DECEMBER 31, 2000

		Common Stock
					Additional Paid-in Capital		Retained Earnings
		Shares	Amount						Total
BALANCES at Inception (April 19, 2000)		—	$	—	$	—	$	—	$	—
	Issuance of common stock to Founders upon initial capitalization, June 16, 2000	6,100		6		609,994		—		610,000
	Issuance of common stock to Fund VIII pursuant to the acquisition of Schmid, June 16, 2000	24,641		25		2,464,075		—		2,464,100
	Issuance of common stock to former Schmid shareholders for the purchase of Schmid, June 16, 2000	7,292		7		729,193		—		729,200
	Issuance of common stock to former Busha shareholder for the purchase of Busha, July 1, 2000	1,000		1		99,999		—		100,000
	Issuance of common stock to Fund VIII pursuant to the acquisition of Busha, July 18, 2000	9,652		10		965,190		—		965,200
	Issuance of common stock to Fund VIII pursuant to the acquisition of Gane, July 7, 2000	23,913		24		2,391,276		—		2,391,300
	Issuance of common stock to Fund VIII pursuant to the acquisition of Sun, August 4, 2000	11,340		11		1,133,989		—		1,134,000
	Net income	—		—		—		704,734		704,734
BALANCES at December 31, 2000		83,938		84		8,393,716		704,734		9,098,534
	Issuance of common stock to Fund VIII pursuant to the acquisition of K&H, January 1, 2001	32,000		32		3,199,968		—		3,200,000
	Issuance of common stock to former K&H shareholders for the purchase of K&H, January 1, 2001	1,000		1		99,999		—		100,000
	Issuance of common stock to Fund VIII pursuant to the acquisition of HB&R, June 1, 2001	114,000		114		11,399,886		—		11,400,000
	Issuance of common stock to Fund VIII pursuant to the conversion of notes payable to equity, June 1, 2001	30,000		30		2,999,970		—		3,000,000
	Issuance of common stock to FESCO management, August 20, 2001	1,050		1		104,999		—		105,000
	Issuance of common stock to former Busha shareholders for settlement of deferred purchase price payments, August 29, 2001	2,000		2		199,998		—		200,000
	Issuance of common stock to former Schmid shareholders for the settlement of deferred purchase price payments, November 9, 2001	9,307		9		930,691		—		930,700
	Net income	—		—		—		930,180		930,180
BALANCES at December 31, 2001		273,295	$	273	$	27,329,227	$	1,634,914	$	28,964,414

The accompanying notes are an integral part of these consolidated statements.

F2-23

FIRST ENERGY SERVICES COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

				Year Ended December 31, 2001			Period From Inception (April 19, 2000) To December 31, 2000
CASH FLOWS FROM OPERATING ACTIVITIES:
	Net income			$	930,180		$	704,734
	Adjustments to reconcile net income to net cash provided by operating activities —
		Depreciation and amortization			7,218,051			1,382,942
		Loss on sale of assets			181,065			8,750
		Deferred income taxes			227,643			88,000
		Amortization of deferred loan fees			69,648			—
		Non-cash interest charges			1,080,041			—
	Changes in current assets and liabilities —
		Receivables			(1,591,279	)		(1,156,103	)
		Inventories			(161,557	)		(63,217	)
		Other current assets			173,624			(210,207	)
		Other non-current assets			(583,353	)		—
		Accounts payable and accrued liabilities			936,697			708,929
		Income taxes receivable/payable			(1,053,180	)		96,807
			Net cash provided by operating activities		7,427,580			1,560,635
CASH FLOWS FROM INVESTING ACTIVITIES:
	Purchases of property, plant and equipment, net				(7,471,332	)		(3,754,329	)
	Purchase of HB&R, net of cash of $1,356,775				(17,053,188	)		—
	Purchase of assets of K&H				(5,536,791	)		—
	Proceeds from sale of property, plant and equipment				235,199			—
	Purchase of Schmid, net of cash of $39,093				—			(3,044,079	)
	Purchase of Gane, net of cash of $482,896				—			(4,605,104	)
	Purchase of Busha, net of cash of $0 and $145,291, respectively				(1,057,000	)		(969,474	)
	Purchase of assets of Sun				—			(2,307,216	)
			Net cash used in investing activities		(30,883,112	)		(14,680,202	)
CASH FLOWS FROM FINANCING ACTIVITIES:
	Proceeds from sale of common stock				14,705,000			7,564,600
	Proceeds from note payable to Fund VIII				10,400,000			7,793,850
	Proceeds from equipment notes payable				4,458,985			2,357,430
	Proceeds from GE Capital financing				941,450			—
	Payment of loan fees				(713,813	)		—
	Repayment of notes payable				(4,522,067	)		(266,612	)
	Payments of line of credit				(44,950	)		(704,396	)
	Repayment of capital lease obligations				(2,022,957	)		(404,454	)
			Net cash provided by financing activities		23,201,648			16,340,418
NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS					(253,884	)		3,220,851
CASH AND CASH EQUIVALENTS, at inception					3,220,851			—
CASH AND CASH EQUIVALENTS, end of period				$	2,966,967		$	3,220,851

The accompanying notes are an integral part of these consolidated statements.

F2-24

FIRST ENERGY SERVICES COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

			Year Ended December 31, 2001		Period From Inception (April 19, 2000) To December 31, 2000
SUPPLEMENTAL CASH FLOW INFORMATION:
	Cash paid during the year for —
		Interest	$	1,976,286	$	948,004
		Taxes	$	2,005,673	$	383,193
SUPPLEMENTAL DISCLOSURE OF NON-CASH INVESTING AND FINANCING ACTIVITIES:
	Common stock issued for the purchase of K&H		$	100,000	$	—
	Common stock issued for the earn-out and purchase of Schmid, respectively		$	930,700	$	729,200
	Common stock issued for the earn-out and purchase of Busha, respectively		$	200,000	$	100,000
	Note payable to fund VIII converted to common stock		$	3,000,000	$	—
	Property acquired through the buy-out of operating leases		$	1,919,624	$	—
	Equipment notes and capital lease obligations refinanced		$	19,639,426	$	—
	Property purchased through capital leases		$	7,315,445	$	—
	Accrued business combination costs		$	—	$	54,507
	Acquisition purchase price accrual		$	348,000	$	319,368

The accompanying notes are an integral part of these consolidated statements.

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FIRST ENERGY SERVICES COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2001 AND 2000

1.    ORGANIZATION AND BUSINESS ACTIVITY:

        First Energy Services Company ("FESCO" or the "Company") was incorporated under the laws of the State of Delaware on April 19, 2000 ("Inception") to acquire and manage oil and gas well site service providers. The Company commenced substantial operations on June 16, 2000 upon the acquisition of Schmid Oilfield Services, Inc. ("Schmid") (Note 3), and subsequently completed several other acquisitions. The Company's operations are conducted entirely in the United States.

2.    SIGNIFICANT ACCOUNTING POLICIES:

Principles of Consolidation

        The consolidated financial statements include the accounts of FESCO and its wholly owned subsidiaries for the period, subsequent to acquisition. All significant intercompany accounts, profits and transactions have been eliminated in consolidation.

Reclassification

        Certain items in the 2000 consolidated financial statements have been reclassified to be consistent with the presentation of such items in the 2001 financial statements.

Use of Estimates

        The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Cash and Cash Equivalents

        Cash and cash equivalents consist of highly liquid investments with original maturities of three months or less. The Company places its temporary cash investments in financial institutions that management believes to be of high credit quality. As such, the Company believes no significant concentration of credit risk exists with respect to these investments.

Inventories

        Inventories consist of fuel, spare parts and supplies used to operate and maintain the Company's vehicles and equipment. Inventories are carried at the lower of cost or market utilizing the first-in, first-out method.

Fair Value of Financial Instruments

        The carrying amounts reported in the accompanying consolidated balance sheets for cash and cash equivalents, trade accounts receivable, accounts payable and accrued liabilities approximate fair value due to the short-term maturities of these instruments. The carrying amounts reported in the accompanying consolidated balance sheets for the line of credit, equipment notes payable,

F2-26

capital lease obligations and note payable to First Reserve Fund VIII L.P. approximate fair value since the applicable interest rates are either variable or representative of rates obtainable by the Company on December 31, 2001 and 2000, respectively.

Property, Plant and Equipment

        Property and equipment are stated at cost and are depreciated on a straight-line basis over the estimated useful lives of the assets as noted below.

Asset	Estimated Useful Lives
Land	Not Depreciated
Buildings and improvements	15 to 40 years
Vehicles and equipment	5 to 8 years
Furniture and fixtures	3 to 5 years
Leased equipment	Term of corresponding lease

        Maintenance and repairs are expensed as incurred. Betterments, major capital improvements and rebuilds that extend the useful life of the property and equipment are capitalized.

Intangibles and Goodwill

        The Company recorded intangible assets, including employment agreements, non-compete agreements, customer lists and goodwill in connection with the acquisitions described in Note 3 in the aggregate amount of $9,256,701 and $4,561,062, in 2001 and 2000, respectively, that are being amortized on a straight-line basis over the estimated useful lives of the assets as noted below. Amounts paid out under earn out arrangements from acquisitions are capitalized when the amounts can be determined with certainty.

Intangible Asset	Estimated Useful Lives
Employment agreement	1-3 years
Non-compete agreements	3 years
Customer lists	10 years
Goodwill	10 years (no amortization beginning January 1, 2002.)

Impairment of Assets

        Long-lived assets and intangible assets are reviewed for impairment if events or circumstances indicate the carrying amount of these assets may not be recoverable. If this review indicates that the carrying value of these assets will not be recoverable, based on future undiscounted net cash flows from the use or disposition of the assets, the carrying value is reduced to fair value.

Income Taxes

        The current provision for income taxes represents estimated amounts due on tax returns filed or to be filed. Deferred tax assets and liabilities are recorded for the estimated future tax effects of

F2-27

temporary differences between the tax basis of assets and liabilities and amounts reported in the consolidated balance sheets. The overall change in deferred tax assets and liabilities for the period, exclusive of deferred tax assets and liabilities recorded in purchase accounting for businesses acquired, measures the deferred tax expense or benefit for the period. Effects of changes in enacted tax laws on deferred tax assets and liabilities are reflected as adjustments to tax expense in the period of enactment.

Concentration of Credit Risk

        The Company's trade accounts receivable are concentrated with certain customers in the oil and gas industry. Although diversified within many companies, collectibility is dependent upon general economic conditions of the oil and gas industry in the regions of operations in which the Company operates. During the year ended December 31, 2001 and the period from Inception to December 31, 2000, virtually all of the Company's revenue came from oil and gas industry customers, with one significant customer contributing 25% and 16%, respectively, of the Company's revenue.

Revenue and Cost Recognition

        Revenues from time-and-material contracts are recognized currently as the work is performed. Revenues from fixed-price construction contracts are recognized on the completed-contract method. This method is used because the typical contract is completed in two months or less and financial position and results of operations do not vary significantly from those which would result from use of the percentage-of-completion method. A contract is considered complete when all costs except insignificant items have been incurred and the Company has received notice of acceptance from the customer. As of December 31, 2001, there were no fixed price construction contracts in place.

        Contract costs include all direct material and labor costs and those indirect costs related to contract performance, such as indirect labor, supplies, tools, repairs, and depreciation costs. Provisions for estimated losses on uncompleted contracts are made in the period in which such losses are determined. Claims are included in revenues when received.

New Accounting Pronouncements

        In June 2001, the Financial Accounting Standards Board ("FASB") issued Statement of Financial Accounting Standards No. 141, "Business Combinations" ("SFAS 141") and Statement of Financial Accounting Standards No. 142, "Goodwill and Other Intangible Assets" ("SFAS 142"). These statements eliminate the availability to apply the pooling-of-interests method of accounting for transactions initiated after June 30, 2001, requires the use of the purchase method of accounting for all combinations after June 30, 2001 and establish a new accounting standard for goodwill acquired in a business combination. SFAS 141 and SFAS 142 continue to require recognition of goodwill as an asset, but do not permit amortization of goodwill as previously required by APB Opinion No. 17, "Intangible Assets." Goodwill will be subject to periodic (at least annual) tests for impairment and recognition of impairment losses in the future could be required based on a fair value model. The Company's prospective financial statements may be significantly affected by the

F2-28

results of future periodic tests for impairment of goodwill. The amount and timing of charges related to goodwill acquired in business combinations will change significantly from prior practice. The Company recorded $467,103 of amortization expense during the year ended December 31, 2001 relating to goodwill that, as a result of the adoption of SFAS 142, will not occur in future periods. There was no effect to the Company at adoption on January 1, 2002 for SFAS No. 142.

        During June 2001, the FASB issued Statement of Financial Accounting Standards No. 143, "Accounting for Asset Retirement Obligations" ("SFAS 143"), SFAS 143 establishes accounting standards for recognition and measurement of a liability for an asset retirement obligation and the associated asset retirement cost. SFAS 143 requires an entity to recognize the fair value of a liability for an asset retirement obligation in the period in which it is incurred if a reasonable estimate can be made. The Company is required to adopt SFAS 143 on January 1, 2003. The Company has not quantified the impact of adoption of SFAS 143 at the current time.

        During August 2001, the FASB issued Statement of Financial Accounting Standards No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" ("SFAS 144"). SFAS 144 supersedes Statement of Financial Accounting Standards No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed of" and the accounting and reporting provisions of APB Opinion No. 30, "Reporting the Results of Operations — Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions." SFAS 144 applies to recognized long-lived assets, including intangible assets, of an entity to be held and used or to be disposed of and does not apply to goodwill, intangible assets not being amortized, financial instruments and deferred tax assets. SFAS 144 requires an impairment loss to be recorded for assets to be held and used when the carrying amount of a long-lived asset is not recoverable and exceeds its fair value. An asset that is classified as held for sale shall be recorded at the lower of its carrying amount or fair value less cost to sell. The Company's adoption of SFAS No. 144 on January 1, 2002 had no impact.

3.    ACQUISITIONS:

K & H Construction, Inc.

        On January 1, 2001, the Company acquired certain assets and liabilities of K & H Construction, Inc., a Wyoming Corporation ("K&H"). The assets acquired are used in the conduct and operations of the oil field construction and gravel crushing business in the Powder River Basin of Wyoming. This transaction was accounted for under the purchase method of accounting.

HB&R, Inc.

        On June 1, 2001, the Company acquired 100% of the outstanding common shares of HB&R, Inc., a Montana Corporation ("HB&R"). HB&R is a provider of hot oiling, fluid hauling, and frac tank rental services to the oil and gas industry in North Dakota, Montana, Wyoming and Alaska. The acquisition was accounted for under the purchase method of accounting and, accordingly, the assets, liabilities and operating results of HB&R have been included in the accompanying consolidated financial statements from June 1, 2001.

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        The following represents the consideration for the acquisitions that occurred during the year ended December 31, 2001:

Summary of Acquisitions	K & H		HB & R
Cash or payable due to sellers	$	5,388,791	$	18,209,963
FESCO stock issued to sellers		100,000		—
Estimated acquisition costs		148,000		200,000
	$	5,636,791	$	18,409,963

        The purchase consideration for HB & R and K & H was allocated based upon the estimated fair value of the assets acquired and liabilities assumed:

	K & H			HB & R
Cash acquired	$	—		$	1,356,775
Accounts receivable		956,709			2,919,641
Property, plant and equipment		7,365,100			15,291,485
Other assets		144,580			689,574
Employment agreements		100,000			—
Non-compete agreements		—			300,000
Customer lists		75,611			2,524,768
Goodwill		75,612			3,302,285
Accounts payable and accrued liabilities		(87,005	)		(1,531,950	)
Debt and capital lease obligations		(2,993,816	)		(1,050,098	)
Deferred tax liabilities		—			(5,392,517	)
Total	$	5,636,791		$	18,409,963

Schmid Oilfield Service, Inc.

        On June 16, 2000, the Company acquired 100% of the outstanding common shares of Schmid, a Wyoming C Corporation. Schmid is a provider of oil field construction and maintenance support services in the mineral, chemical, utility and petroleum industries of the Green River and Powder River Basins of Wyoming.

        The aggregate consideration paid by the Company consisted of cash and 7,292 shares of the Company's stock. Additional cash consideration in the form of an Earn-out Payment may be paid to the former shareholders of Schmid in 2002. The Earn-out Payment is based upon the amount of EBITDA, as defined, earned by Schmid for the two year period ending March 31, 2002 and accrues interest from March 31, 2001 to March 31, 2002 at a rate equal to the prime interest rate plus 1.0%. The acquisition was accounted for under the purchase method of accounting and, accordingly, the assets, liabilities and operating results of Schmid have been included in the accompanying consolidated financial statements from June 16, 2000.

        In November 2001, a portion of the Earn-out Payment was paid through the issuance of 9,307 shares of the Company's common stock, value at $930,700. This additional consideration paid in

F2-30

partial satisfaction of the Earn-out Payment has been recorded as an addition to intangible assets in the accompanying consolidated financial statements.

Gane Production Services, Inc.

        On July 1, 2000, the Company acquired 100% of the outstanding common shares of Gane Production Services, Inc., a Wyoming Subchapter S Corporation ("Gane"). Gane is a provider of oil and gas maintenance and construction services in the Powder River Basin of Wyoming. The acquisition was accounted for under the purchase method of accounting and, accordingly, the assets, liabilities and operating results of Gane have been included in the accompanying consolidated financial statements from July 1, 2000.

Busha Enterprises, Inc.

        On July 1, 2000, the Company acquired 100% of the outstanding common shares of Busha Enterprises, Inc., a Colorado Corporation ("Busha"). Busha is a provider of fluid hauling services to the oil and gas industry in the DJ and Piceance Basins of Colorado. The acquisition was accounted for under the purchase method of accounting and, accordingly, the assets, liabilities and operating results of Busha have been included in the accompanying consolidated financial statements from July 1, 2000.

        Additional cash consideration in the form of an Earn-out Payment was paid to the sellers in August 2001 through the issuance of 2,000 shares of the Company's common stock, valued at $200,000 and a cash payment in the amount of $1,057,000. The total Earn-out Payment of $1,257,000 has been recorded as an addition to goodwill in the accompanying consolidated financial statements.

Sun Cementing of Wyoming, Inc.

        Effective July 1, 2000, the Company acquired certain assets and liabilities of Sun Cementing of Wyoming, Inc., a Wyoming Corporation ("Sun"). The assets acquired are used in the conduct and operation of the cementing business in Gillette, Wyoming. This transaction was accounted for under the purchase method of accounting.

        The following represents the consideration for the acquisitions that occurred during the period from Inception to December 31, 2000:

Summary of Acquisitions	Schmid		Gane		Busha		Sun
Cash or payable due to sellers	$	3,141,568	$	5,001,626	$	1,075,491	$	2,333,342
FESCO stock issued to sellers		729,200		—		100,000		—
Estimated acquisition costs		115,000		100,000		100,000		100,000
		3,985,768		5,101,626		1,275,491		2,433,342
Earn-out consideration paid in 2001		930,700		—		1,257,000		—
	$	4,916,468	$	5,101,626	$	2,532,491	$	2,433,342

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        The purchase consideration for Schmid, Gane, Busha and Sun was allocated on a final basis based upon the estimated fair value of the assets acquired and liabilities assumed:

	Schmid			Gane			Busha			Sun
Accounts receivable	$	2,093,129		$	819,796		$	680,980		$	—
Property, plant and equipment		6,126,132			2,045,000			1,336,550			1,733,500
Other assets		102,695			569,682			161,570			20,000
Intangibles		1,297,000			1,586,227			444,532			489,842
Goodwill		298,066			1,497,405			1,616,012			210,401
Accounts payable and accrued liabilities		(1,312,186	)		(250,866	)		(279,564	)		(20,401	)
Debt and capital lease obligations		(2,123,632	)		(107,691	)		(1,082,945	)		—
Deferred tax liabilities		(1,564,736	)		(1,057,927	)		(344,644	)		—
Total	$	4,916,468		$	5,101,626		$	2,532,491		$	2,433,342

4.    PROPERTY, PLANT AND EQUIPMENT:

	December 31,
	2001			2000
Land	$	391,554		$	10,000
Buildings and improvements		2,296,891			549,973
Vehicles and equipment		50,133,486			14,060,901
Furniture and fixtures		551,929			135,759
		53,373,860			14,756,633
Less — accumulated depreciation		(6,513,930	)		(962,787	)
Construction in progress		363,574			230,129
	$	47,223,504		$	14,023,975

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5.    INTANGIBLE ASSETS AND GOODWILL:

			December 31,
			2001			2000
Intangible Assets
	Employment agreements		$	697,000		$	597,000
	Non-compete agreements			840,000			540,000
	Customer lists			5,280,982			1,749,902
				6,817,982			2,886,902
		Less — accumulated amortization		(1,227,530	)		(338,200	)
			$	5,590,452		$	2,548,702
Goodwill
	Goodwill		$	6,999,781		$	1,674,160
		Less — accumulated amortization		(663,486	)		(81,955	)
			$	6,336,295		$	1,592,205

6.    LONG-TERM DEBT AND CAPITAL LEASE OBLIGATIONS:

Long-Term Debt

        A summary of the Company's notes payable as of December 31, 2001 is as follows:

GE Capital Revolving Credit Facility	$	290,681
GE Capital Term Loan		13,562,500
GE Capital Acquisition Term Loan		8,233,375
Equipment notes payable		4,908,163
		26,994,719
Less: current portion		(4,161,558	)
	$	22,833,161

        On August 30, 2001, the Company and certain of its subsidiaries entered into a credit agreement (the "Agreement") with General Electric Capital Corporation ("GE Capital") to refinance certain equipment notes payable assumed through the acquisition of the Company's subsidiaries and the funds borrowed from the Company's majority shareholder, First Reserve Fund VIII L.P. ("Fund VIII"). The Agreement allows for borrowings up to an aggregate sum of $30,000,000, consisting of a Revolving Credit Facility, a Term Loan, an Acquisition Term Loan, a Swing Line Facility and Letters of Credit. All borrowings under the Agreement bear interest at variable interest rates as explained below. The Agreement calls for mandatory prepayments equal to the proceeds from the sale of fixed assets, the proceeds in excess of $250,000 from the sale of Company common stock, and Excess Cash Flow, as defined, beginning in the year ending December 31, 2002. The Agreement is guaranteed by the Company and is secured by all of the Company's personal and real property. Loan origination fees of $1,073,392 were incurred in connection with the Agreement. These fees are included in other assets in the accompanying consolidated balance

F2-33

sheets and are being amortized to interest expense using the straight-line method over the terms of the loans, which approximates the effective interest method. A commitment fee of 0.5% of the average remaining available borrowings is due monthly.

        Borrowings under the Revolving Credit Facility may be repaid at any time without penalty but must be repaid in full by August 30, 2006; may not exceed $7,500,000; bear interest at either a) the Index Rate, as defined, plus 1.75% (7.25% as of December 31, 2001), or b) the Company may commit a portion of the outstanding borrowings under the Revolving Credit Facility to one, two or three months terms bearing interest at the LIBOR Rate, as defined, plus 3.25% (5.68% as of December 31, 2001). The Company is required to pay a monthly commitment fee equal to 0.50% of the remaining funds available under the Revolving Credit Facility. As of December 31, 2001, the Company had aggregate borrowings outstanding under the Revolving Facility of $290,681.

        Total principal borrowed on August 30, 2001 under the Term Loan as $14,000,000. The Term Loan bears interest at the Company's option of either a) the Index Rate, as defined, plus 2.00% (7.50% as of December 31, 2001) or b) the LIBOR Rate plus 3.50% (5.93% as of December 31, 2001). Commencing December 31, 2001, accrued interest computed on the outstanding Term Loan balance is due monthly and principal repayments of $437,500 are due quarterly with the remaining principal balance due at August 30, 2006. The Term Loan may be prepaid at any time in the minimum amount of $500,000, and such repayment is subject to a declining prepayment penalty that terminates August 30, 2002. As of December 31, 2001, the Company had aggregate borrowings outstanding under the Term Loan of $13,562,500.

        Total principal borrowed on August 30, 2001 under the Acquisition Term Loan was $8,500,000. The Acquisition Term Loan bears interest at either a) the Index Rate, as defined, plus 2.00% (7.50% as of December 31, 2001) or b) the Company may commit a portion of the outstanding borrowings under the Acquisition Term Loan to one, two or three month terms bearing interest at the LIBOR Rate, as defined, plus 3.50% (5.93% as of December 31, 2001). Commencing December 31, 2001, accrued interest computed on the outstanding Acquisition Term Loan balance is due monthly and principal repayments of $266,625 are due quarterly with the remaining principal balance due at August 30, 2006. The Acquisition Term Loan may be prepaid at any time in the minimum amount of $500,000, and such repayment is subject to a declining prepayment penalty that terminates on August 30, 2002. As of December 31, 2001, the Company had aggregate borrowings outstanding under the Acquisition Term Loan of $8,233,375

        To the extent that the Company's Borrowing Base, as defined, exceeds that used to determine the initial $30,000,000 credit limit under the Agreement, additional funds will be available to the Company by utilizing the Swing Line Facility. As of December 31, 2001, the Company had no borrowings under the Swing Line Facility. The Borrowing Base as of December 31, 2001 was $8,203,721.

        The Company may request Letters of Credit from time to time from GE Capital in an amount not to exceed the lesser of $1,000,000 or the funds remaining under the Revolving Credit Facility. Outstanding Letters of Credit bear a fee equal to 3.25% of the outstanding amount. The Company had no Letters of Credit outstanding as of or during the year ended December 31, 2001.

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        Aggregate indebtedness to GE Capital under the Revolving Credit Facility, Term Loan and Acquisition Term Loan as of December 31, 2001 was $22,086,556, of which $21,000,000 bore interest at the LIBOR Rate plus 3.50%, $290,861 bore interest at the Index Rate plus 1.75% and $795,695 bore interest at the Index Rate plus 2.00%. The weighted average interest rate for the period these borrowings were outstanding in 2001 was 6.62%. For the year ended December 31, 2001, total interest expense related to these borrowings was $524,520.

        The Agreement is subject to various financial and non-financial covenants. GE Capital has the option to call the debt in the event of noncompliance with these covenants. The Company was in compliance with all covenants as of December 31, 2001.

        On June 16, 2000, the Company entered into senior secured promissory note agreement with Fund VIII. The agreement was for an initial $1,890,410 upon the acquisition of Schmid and was subsequently restated and increased with each additional acquisition. At the time of the GE Capital Agreement, the total borrowings under the Fund VIII note were $18,269,898. The Fund VIII note was repaid in full in conjunction with the GE Capital credit arrangement. Of this amount $15,269,898 was repaid to Fund VIII and $3,000,000 was converted to equity. The note required interest to be repaid to Fund VIII on a graduating scale, beginning at 9% per annum and ending at 21% per annum when the note originally matured on June 4, 2001. Monthly payments of accrued interest were required with the principal balance due at maturity. During the year ended December 31, 2001, interest expense related to the Fund VIII note was $715,267.

        The Company acquired a line of credit agreement with a bank in conjunction with the Busha acquisition totaling $100,000. The line of credit was secured by certain of the Company's equipment. The line was repaid in full and cancelled in conjunction with the GE Capital credit arrangement.

        The Company has entered into various notes for the purchase of equipment and vehicles bearing interest at rates ranging from 0% to 11% per annum which mature at various dates from February 2002 to January 2007. These notes are collateralized by related equipment and vehicles.

        At December 31, 2001, aggregate scheduled maturities of long-term debt are as follows:

		GE Capital		Equipment Notes		Total
Year ending December 31 —
	2002	$	3,107,181	$	1,054,377	$	4,161,588
	2003		2,816,500		1,087,659		3,904,159
	2004		2,816,500		1,020,992		3,837,492
	2005		2,816,500		994,419		3,810,919
	2006		10,529,875		747,769		11,277,644
	Thereafter		—		2,947		2,947
	Total	$	22,086,556	$	4,908,163	$	26,994,719

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Capital Lease Obligations

        The Company has entered into various capital lease obligations for equipment and vehicles. The obligations bear interest at rates ranging from 7.5% to 9.4% per annum and mature at various dates from April 2005 to June 2006. The lease obligations are collateralized by the related equipment and vehicles which have a net book value of approximately $5,966,047 and $3,167,817 at December 31, 2001 and 2000, respectively.

        At December 31, 2001, future minimum payments required under capital lease obligations are as follows:

Year ending December 31 —
	2002	$	1,912,687
	2003		1,779,047
	2004		1,779,047
	2005		912,938
	2006		218,066
	Less: Interest		6,601,785
			(936,933	)
	Future minimum principal payments		5,664,852
	Less: Current portion		(1,493,165	)
	Long-term portion of capital lease obligations	$	4,171,687

7.    STOCKHOLDERS' EQUITY:

Common and Preferred Stock

        The Company is authorized to issue 500,000 shares of $0.001 par value common stock and 500,000 shares of $.01 par value preferred stock. The rights, terms and conditions of the preferred shares will be determined by the Board of Directors prior to issuance of any series of preferred stock.

Restricted Shares

        The Company's stock may not be transferred without the consent of the Company. Upon consent by the Company of any share transfers, Fund VIII has a right of first refusal to purchase such shares from the selling shareholder based upon the then fair value of the shares. Furthermore, if greater than 50% of the Company's fully diluted common stock is transferred, any remaining shareholders will be required to transfer their shares to the acquirer.

Stock Options

        The Company's 2000 Stock Option Plan (the "2000 Plan"), provides for the grant of options to purchase up to an aggregate of 21,053 shares of common stock of FESCO by employees and nonemployees; of which 10,403 shares are available for grant as of December 31, 2001. The

F2-36

exercise price of nonqualified options granted is determined by the Board of Directors based on the estimated fair market value of FESCO common stock at the date of grant. The 2000 Plan allows for option awards to be granted for ten years from the effective date of the plan, which was June 16, 2000, and options granted have a term of ten years. Options vest as determined by the Board. Since inception, the Board has issued time and performance awards. Time awards vest over four years, with one-fourth vesting at the end of each year. Performance awards vest based on a formula which will not be computed until the date of a Liquidity Event, as defined. Since the number of shares which will be exercisable is not fixed, the performance awards are accounted for under variable accounting and stock-based compensation expense may be recorded in the future when the shares under grant become exercisable. The amount of compensation per share will be the difference between the fair value per share of common stock minus the exercise price. If employment is terminated for any reason, vested options must be exercised within 90 days of termination or they are automatically canceled.

        During 2000, the Company granted 3,049 stock options to employees with an exercise price of $100 per share and weighted average fair value of $26.11 per option. During 2001, the Company granted 7,601 options to employees with an exercise price of $100 per share and a weighted average fair value of $21.24 per option. As of December 31, 2001, 381 of these options are exercisable. These options have an estimated remaining contractual life of 9.2 years. No options have been granted to non-employees.

Fair Value Disclosures

        The Company calculated the minimum fair value of each option grant on the date of grant using the minimum value method utilizing Black-Scholes option pricing model as prescribed by SFAS No. 123 using the following assumptions during the year ended December 31, 2001 and for the period from Inception to December 31, 2000.

	2001		2000
Weighted average risk-free interest rate	4.84	%	6.14	%
Expected lives, in years	5.0		5.0
Dividend yield	N/A		N/A

        The pro forma compensation cost associated with the Company's stock-based compensation plans, determined using the minimum value method prescribed by SFAS No. 123, results in a pro forma charge of approximately $43,300 and $10,000 to the reported net income during the year ended December 31, 2001 and for the period from inception to December 31, 2000, respectively.

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8.    INCOME TAXES:

        The provision (benefit) for income taxes consists of the following:

			Year Ended December 31, 2001		Period From Inception to December 31, 2000
Current:
	Federal		$	521,200	$	474,800
	State			53,000		5,200
Current provision				574,200		480,000
Deferred:
	Federal			209,185		83,200
	State			18,458		4,800
Deferred provision				227,643		88,000
		Total	$	801,843	$	568,000

        The following is a reconciliation of the difference between the actual provision for income taxes and the provision computed by applying the federal statutory rate of 34% to income before income taxes for the year ended December 31, 2001 and for the period from Inception to December 31, 2001:

	Year Ended December 31, 2001		Period From Inception to December 31, 2000
Provision at statutory rate	$	588,898	$	432,800
Non-deductible items including non amortizable intangibles		178,019		131,300
State taxes and other		34,926		3,900
	$	801,843	$	568,000

        Net deferred tax liabilities are recognized for the future tax consequences of differences between the carrying amounts of assets and liabilities and their respective tax bases using enacted tax rates in effect for the year in which the differences are expected to reverse. The net deferred tax liability consists of differences in amortization rates between book and tax depreciation and amortization of intangible assets and property, plant and equipment. Upon the closing of the acquisitions discussed in Note 3, $5,392,517 and $2,967,307 for the year ended December 31, 2001 and for the period from inception to December 31, 2000, respectively, was recorded as a deferred tax liability due to the excess of book basis over acquired tax basis.

        Prior to the acquisition of Gane, this subsidiary filed with the Internal Revenue Service as a subchapter S Corporation. Although the Company is a subchapter C Corporation, the ownership of this subsidiary could expose the Company to liabilities from this subsidiary's previous tax activity if

F2-38

their subchapter S Corporation status were denied by the Internal Revenue Service for any period prior to the Company's acquisition of this subsidiary.

9.    COMMITMENTS AND CONTINGENCIES:

Operating Lease Commitments

        The Company has entered into noncancelable operating leases for equipment and real property with lease terms through 2004. Future minimum lease payments at December 31, 2001 are as follows:

Year ending December 31 —
	2002		$	228,400
	2003			67,890
	2004			1,650
		Total minimum payments	$	297,940

        Rental expense for the year ended December 31, 2001 and for the period from Inception through December 31, 2001 for operating leases was $1,265,588 and $192,548, respectively.

Employee Retirement Plans

        The Company provides voluntary 401(k) employee savings plans covering all eligible employees of its Schmid, Sun and HB&R subsidiaries (the "401(k) Plans"). Participants in the 401(k) Plans may contribute up to 20% of their eligible compensation. Qualified and non-qualified, discretionary employer contributions may be made by the Company which are allocated to eligible employees based upon their representative share of total compensation paid to eligible employees during the year. Participant and qualified employer contributions vest immediately, whereas non-qualified employer contributions vest ratably until the participant reaches their sixth year of service. During the year ended December 31, 2001 and for the period from Inception to December 31, 2000, the Company contributed $22,804 and $250, respectively, to the 401(k) Plans.

        The Company provides a Simple IRA plan covering all eligible employees of its Busha, Gane and K&H subsidiaries (the "SEP Plan"). Participants may contribute to the SEP Plan up to $6,000 annually. The Company must make annual elections, either a matching contribution up to 3% of the participants' compensation or a non-elective contribution equal to 2% of the participants' salary to the plan. During the year ended December 31, 2001 and for the period from inception to December 31, 2000, the Company contributed $65,074 and $6,748, respectively, to the SEP Plan.

        The Company is in the process of consolidating the 401(k) Plans and the SEP Plan into one 401(k) plan.

10.    RELATED PARTIES:

        In connection with the acquisition of Schmid and in order to comply with a non-compete agreement related to one of the Company's original founders, certain assets were transferred from

F2-39

the Company into a new entity owned by the former owners of Schmid. As of December 31, 2000, the Company had receivables of $51,789 from this entity and payables of $323,964, to this entity related to the transfer of assets effected upon the acquisition of Schmid. The Company had no receivables from this entity or payables to this entity as of December 31, 2001.

        The Company leases various land and buildings from entities owned by the former owners of Schmid, Busha and Gane under the operating leases described above. Total rental payments to the entities owned by the former owners of Schmid, Busha and Gane related to these leases were $0, $49,920 and $38,000 and $20,700, $24,000 and $18,000, respectively, and the monthly rental payments to these entities were $0, $4,160 and $4,000 and $3,450, $4,000 and $3,000 per month, respectively, for the year ended December 31, 2001 and for the period ended December 31, 2000, respectively.

11.    SUBSEQUENT EVENT (UNAUDITED):

        In March of 2002, the Company issued 130,000 shares of common stock to Fund VIII in exchange for $13,000,000 in cash. The Company intends to use the investment to pay down the Acquisition Term Loan, and for operating cash flow as needed.

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FESCO Holdings, Inc.

and Subsidiaries

Consolidated Balance Sheet

			September 30, 2003
			(Unaudited)
Assets
Current assets:
	Cash and cash equivalents		$	1,895,738
	Trade accounts receivable, net of allowance for doubtful accounts of $70,201			11,648,413
	Other receivables			72,636
	Inventories			781,049
	Prepaid expenses and other current assets			595,792
		Total current assets		14,993,628
Property, plant, and equipment, net				32,343,500
Other assets				852,877
		Total assets	$	48,190,005
Liabilities and Stockholders' Equity
Current liabilities:
	Accounts payable		$	1,209,157
	Accrued liabilities			3,004,354
	Line of credit			140,915
	Current portion of long-term debt			3,746,980
	Current portion of capital lease obligations			1,390,560
		Total current liabilities		9,491,966
Long-term debt, net of current portion				13,244,240
Capital lease obligations, net of current portion				1,791,640
Other long-term liabilities				40,000
		Total liabilities		24,567,846
Commitments and contingencies (note 8)
Stockholders' equity:
	Preferred stock, $0.01 par value. 500,000 shares authorized; no shares issued and outstanding			—
	Common stock, $0.001 par value. 500,000 shares authorized; 406,607 shares issued and outstanding			406
	Additional paid-in capital			40,660,294
	Accumulated deficit			(17,038,541	)
		Total stockholders' equity		23,622,159
		Total liabilities and stockholders' equity	$	48,190,005

See accompanying notes to consolidated financial statements.

F2-41

FESCO Holdings, Inc.

and Subsidiaries

Consolidated Statements of Operations

			Nine Months Ended September 30,
			2003			2002
			(Unaudited)
Sales:
	Fluid services		$	13,132,175		$	14,713,515
	Pressure pumping			1,344,189			1,933,077
	Construction			21,788,751			20,337,285
				36,265,115			36,983,877
Cost of sales:
	Fluid services			10,232,784			11,062,775
	Pressure pumping			1,229,642			1,362,754
	Construction			16,806,682			15,659,539
	Selling, general, and administrative			4,433,619			4,917,368
	Depreciation and amortization			6,370,847			6,188,353
	Impairment loss			18,362,450			—
	Loss (gain) on sale of assets			446,450			1,261,671
				57,882,474			40,452,460
		Operating loss		(21,617,359	)		(3,468,583	)
Interest expense				993,972			1,168,766
		Net loss before income taxes		(22,611,331	)		(4,637,349	)
Income tax benefit				7,779,010			1,583,052
		Net loss to common shareholders	$	(14,832,321	)	$	(3,054,297	)

See accompanying notes to consolidated financial statements.

F2-42

FESCO Holdings, Inc.

and Subsidiaries

Consolidated Statement of Stockholders' Equity

	Common stock
				Additional paid-in capital		Accumulated deficit
	Shares	Amount							Total
Balance at December 31, 2002	406,607	$	406	$	40,660,294	$	(2,206,220	)	$	38,454,480
Net loss	—		—		—		(14,832,321	)		(14,832,321	)
Balance at September 30, 2003 (Unaudited)	406,607	$	406	$	40,660,294	$	(17,038,541	)	$	23,622,159

See accompanying notes to consolidated financial statements.

F2-43

FESCO Holdings, Inc.

and Subsidiaries

Consolidated Statements of Cash Flows

					Nine Months Ended September 30,
					2003			2002
					(Unaudited)
Cash flows from operating activities:
	Net loss				$	(14,832,321	)	$	(3,054,297	)
	Adjustments to reconcile net loss to net cash provided by operating activities:
		Depreciation and amortization				6,370,847			6,188,353
		Impairment loss				18,362,450			—
		Loss on sale of assets				446,450			1,261,671
		Deferred income taxes				(7,779,010	)		(1,583,052	)
		Amortization of deferred loan fees				210,636			107,340
		Changes in current assets and liabilities:
			Receivables			(1,021,344	)		1,443,908
			Inventories			(44,391	)		(180,689	)
			Other current assets			(205,800	)		50,664
			Other noncurrent assets			—			278,543
			Accounts payable and accrued liabilities			(496,299	)		(1,552,097	)
				Net cash provided by operating activities		1,011,218			2,960,344
Cash flows from investing activities:
	Purchases of property, plant, and equipment					(927,464	)		(1,847,635	)
	Proceeds from sale of property, plant, and equipment					332,337			1,159,209
	Schmid acquisition earn-out payment					(406,857	)		—
				Net cash used in investing activities		(1,001,984	)		(688,426	)
Cash flows from financing activities:
	Proceeds from sale of common stock					—			13,000,000
	Repayment of long-term debt and capital lease obligations					(2,905,871	)		(11,764,225	)
	Advance from (repayment of) line of credit					140,915			(266,596	)
				Net cash provided by (used in) financing activities		(2,764,956	)		969,179
				Net increase (decrease) in cash and cash equivalents		(2,755,722	)		3,241,097
Cash and cash equivalents, beginning of period						4,651,460			2,966,967
Cash and cash equivalents, end of period					$	1,895,738		$	6,208,064
Supplemental cash flow information:
	Cash paid during the period for:
		Interest			$	776,443		$	1,310,400
Noncash investing and financing activities:
	Assets obtained by capital lease				$	2,234,474		$	477,628

See accompanying notes to consolidated financial statements.

F2-44

FESCO HOLDINGS, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

SEPTEMBER 30, 2003

(1) Organization and Business Activity

        First Energy Services Company ("FESCO" or the "Company") was incorporated under the laws of the State of Delaware on April 19, 2000 (Inception) to acquire and manage oil and gas well site service providers. The Company commenced substantial operations on June 16, 2000 upon the acquisition of Schmid Oilfield Services, Inc. (Schmid), and subsequently completed several other acquisitions. The Company's operations are conducted entirely in the United States.

        On August 30, 2002, the Company restructured the organization to better-align its acquisitions into geographic regions. All wholly owned subsidiaries, except HB&R (note 3), were merged with and into the Company. Operations were divided into specific geographic regions and began operating under the First Energy name. In connection with the restructuring, a new holding company, FESCO Holdings, Inc. ("Holdings"), was incorporated in the state of Delaware to acquire all of the outstanding shares of FESCO.

(2) Significant Accounting Policies

(a) Principles of Consolidation

        The consolidated financial statements include the accounts of Holdings and its wholly owned subsidiaries for the period, subsequent to acquisition. All significant intercompany accounts, profits and transactions have been eliminated in consolidation.

(b) Use of Estimates

        The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

        In the opinion of management, the Company's unaudited consolidated financial statements as of September 30, 2003 and for the interim periods ended September 30, 2003 and 2002 include all adjustments which are necessary for a fair presentation in accordance with accounting principles generally accepted in the United States.

        Certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States have been condensed or omitted herein pursuant to the rules and regulations of the Securities and Exchange Commission ("SEC"). These consolidated financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto included in the Company's 2002 financial statements.

(c) Cash and Cash Equivalents

        Cash and cash equivalents consist of highly liquid investments with original maturities of three months or less. Holdings places its temporary cash investments in financial institutions that management believes to be of high credit quality. As such, Holdings believes no significant concentration of credit risk exists with respect to these investments.

F2-45

(d) Inventories

        Inventories consist of raw materials, fuel, spare parts and supplies used to operate and maintain Holdings' vehicles and equipment. Inventories are carried at the lower of cost or market utilizing the first-in, first-out method.

(e) Fair Value of Financial Instruments

        The carrying amounts reported in the accompanying consolidated balance sheets for cash and cash equivalents, trade accounts receivable, accounts payable and accrued liabilities approximate fair value due to the short-term maturities of these instruments. The carrying amounts reported in the accompanying consolidated balance sheet for the line of credit, long-term debt and capital lease obligations approximate fair value since the applicable interest rates are either variable or representative of rates obtainable by Holdings on September 30, 2003.

(f) Property, Plant, and Equipment

        Property and equipment are stated at cost and are depreciated on a straight-line basis over the estimated useful lives of the assets as noted below.

Asset	Estimated useful lives
Land	Not depreciated
Buildings and improvements	15 to 40 years
Vehicles and equipment	5 to 8 years
Furniture and fixtures	3 to 5 years
Leased equipment	Term of corresponding lease

        Maintenance and repairs are expensed as incurred. Betterments, major capital improvements and rebuilds that extend the useful life of the property, plant, and equipment are capitalized.

(g) Intangible Assets

        Holdings recorded intangible assets, including employment agreements, noncompete agreements and customer lists in connection with acquisitions that are being amortized on a straight-line basis over the estimated useful lives of the assets as noted below. Amounts paid out under earn-out arrangements from acquisitions are capitalized when the amounts can be determined with certainty.

Intangible asset	Estimated useful lives
Employment agreements	1 to 3 years
Noncompete agreements	3 years
Customer lists	10 years

        In September 2003, the Company recognized an impairment loss related to intangible assets totaling $4,003,125. The loss was based on a comparison of the fair value of the underlying

F2-46

intangible asset to its carrying value. There is significant judgment used in determining the fair value of the underlying asset. (See Note 11).

(h) Goodwill

        Holdings recorded goodwill in connection with the acquisitions described in note 1. Prior to the adoption of Statement of Financial Accounting Standards No. 142, Goodwill and Other Intangible Assets ("SFAS 142") on January 1, 2002, Holdings amortized goodwill over an estimated useful life of 10 years. Beginning in fiscal 2002, in connection with the adoption of SFAS 142, Holdings no longer amortizes goodwill. Goodwill is evaluated at least annually for impairment in accordance with the provisions of SFAS 142.

        In September 2003, the Company recognized impairment loss related to goodwill totaling $9,299,013. Impairment analysis requires management to make a series of critical assumptions to: (1) evaluate whether any impairment exists; and (2) measure the amount of impairment. (See Note 11).

(i) Impairment of Assets

Long-Lived Assets Held and Used

        The Company tests long-lived assets or asset groups for recoverability when events or changes in circumstances indicate that their carrying amount may not be recoverable. Circumstances which could trigger a review, include, but are not limited to: significant decreases in the market price of the asset; significant adverse changes in the business climate or legal factors; current period cash flow or operating losses combined with a history of losses or a forecast of continuing losses associated with the use of the asset. Recoverability is assessed based on the carrying amount of the asset and its fair value which is generally determined based on the sum of the undiscounted cash flows expected to result from the use and the eventual disposal of the asset, as well as specific appraisal in certain instances. An impairment loss is recognized when the carrying amount is not recoverable and exceeds fair value (See Note 11).

Long-Lived Assets Held for Sale

        Long-lived assets are classified as held for sale when certain criteria are met, which include: management commitment to a plan to sell the assets; the availability of the assets for immediate sale in their present condition; whether an active program to locate buyers and other actions to sell the assets has been initiated; whether the sale of the assets is probable and their transfer is expected to qualify for recognition as a completed sale within one year; whether the assets are being marketed at reasonable prices in relation to their fair value; and how unlikely it is that significant changes will be made to plan to sell the assets. The Company measures long-lived assets to be disposed of by sale at the lower of carrying amount and fair value less cost to sell. Fair value is determined using quoted market prices or the anticipated cash flows discounted at a rate commensurate with the risk involved (See Note 11).

F2-47

Recent Accounting Pronouncements

        Long-lived assets and intangible assets are reviewed for impairment in accordance with the provisions of Statement of Financial Accounting Standards No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets ("SFAS 144"), whenever changes in events or circumstances indicate the carrying amount of these assets may not be recoverable. If this review indicates that the carrying value of these assets will not be recoverable, based on future undiscounted net cash flows from the use or disposition of the assets, the carrying value is reduced to estimated fair value. During the third quarter of 2003, the Company recorded impairment loss of $5,060,312, under SFAS No. 144 (see Note 11).

(j) Income Taxes

        The current provision for income taxes represents estimated amounts due on tax returns filed or to be filed. Deferred tax assets and liabilities are recorded for the estimated future tax effects of temporary differences between the tax basis of assets and liabilities and amounts reported in the consolidated balance sheets. The overall change in deferred tax assets and liabilities for the period, exclusive of deferred tax assets and liabilities recorded in purchase accounting for businesses acquired, measures the deferred tax expense or benefit for the period. Effects of changes in enacted tax laws on deferred tax assets and liabilities are reflected as adjustments to tax expense in the period of enactment.

(k) Concentration of Credit Risk

        Holdings' trade accounts receivable are concentrated with certain customers in the oil and gas industry. Although diversified among many companies, collectibility is dependent upon general economic conditions of the oil and gas industry in the regions in which Holdings operates. During the nine-month period ended September 30, 2003, virtually all of Holdings revenue came from oil and gas industry customers, with two significant customers contributing 45.3% of Holdings' revenue. Sales to Customer A were approximately $10,099,000, or 27.8%, and sales to Customer B were approximately $6,332,000 or 17.5% of total revenues. During the nine month period ended September 30, 2002, virtually all of Holdings revenue came from oil and gas industry customers, with two significant customers contributing 29.8% of Holdings' revenue. Sales to Customer A were approximately $7,057,000 or 19.08%, and sales to Customer B were approximately $3,976,000 or 10.7% of total revenues.

(l) Revenue and Cost Recognition

        Revenues from time-and-material contracts are recognized currently as the work is performed. Costs include all direct material and labor costs and those indirect costs related to contract performance, such as indirect labor, supplies, tools, repairs, and depreciation costs.

(m) New Accounting Pronouncements

        During June 2001, the FASB issued Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations ("SFAS 143"). SFAS 143 establishes accounting standards for recognition and measurement of a liability for an asset retirement obligation and the

F2-48

associated asset retirement cost. SFAS 143 requires an entity to recognize the fair value of a liability for an asset retirement obligation in the period in which it is incurred if a reasonable estimate can be made. Holdings adopted SFAS 143 on January 1, 2003. The adoption of SFAS 143 had no significant impact on Holdings.

        In April 2002, the FASB issued 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 ("FAS 145"). This Statement rescinds FASB Statement No. 4, Reporting Gains and Losses from Extinguishment of Debt, and an amendment of that statement, FASB Statement No. 64, Extinguishments of Debt Made to Satisfy Sinking-Fund Requirements. This statement amends FASB Statement No. 13, Accounting for Leases, to eliminate an inconsistency between the required accounting for sale-leaseback transactions and the required accounting for certain lease modifications that have economic effects that are similar to the sale-leaseback transactions. FAS 145 was effective for the Company for fiscal year 2002. The adoption of FAS 145 did not have a significant effect on the Company's results of operations or its financial position.

        In June 2002, the FASB issued Statement of Financial Accounting Standards No. 146, Accounting for Costs Associated with Exit or Disposal Activities ("FAS 146"). This statement requires costs associated with exit or disposal activities, such as lease termination or employee severance costs, to be recognized when they are incurred rather than at the date of a commitment to an exit or disposal plan. FAS 146 replaces Emerging Issues Task Force Issue No. 94-3, Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring), which previously provided guidance on this topic. FAS 146 is to be applied prospectively to exit or disposal activities initiated after December 31, 2002. The adoption of FAS 146 did not have a significant effect on the Holdings results of operations or its financial position.

        In November 2002, the FASB issued FASB Interpretation No. 45 ("FIN 45"), Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others. FIN 45 requires that a liability be recorded in the guarantor's balance sheet upon issuance of a guarantee. In addition, FIN 45 requires disclosures about the guarantees that an entity has issued. As FESCO has not entered into such guarantee agreements, the adoption of FIN 45 had no effect on Holdings financial statements as of September 30, 2003.

        In December 2002, the FASB issued Statement of Financial Accounting Standards No. 148, Accounting for Stock-Based Compensation — Transition and Disclosure — An Amendment to FASB Statement No. 123 (FAS 148). This statement amends FAS 123, to provide alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation. In addition, FAS 148 amends the disclosure requirements of FAS 123 to require prominent disclosures in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on reported results. The adoption of FAS 148 did not have a significant effect on Holdings results of operations or its financial position.

        In January 2003, the FASB issued FASB Interpretation No. 46 ("FIN 46"), Consolidation of Variable Interest Entities, an Interpretation of ARB No. 51. FIN 46 requires certain variable interest entities (VIEs) to be consolidated by the primary beneficiary of the entity if the equity investors in

F2-49

the entity do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support from other parties. FIN 46 is effective for all new VIEs created or acquired after January 31, 2003. For VIEs created or acquired prior to February 1, 2003, the provisions of FIN 46 must be applied for the first interim or annual period beginning after June 15, 2003. The adoption of this standard had no effect on FESCO's financial statements.

(3) Acquisition Earn-out Payments

        In accordance with the original terms of the Schmid acquisition agreement, additional cash consideration in the form of an earn-out payment was required to be paid to the former shareholders of Schmid in 2002. The earn-out payment was to be based upon the amount of EBITDA, as defined, earned by Schmid for the two-year period ending March 31, 2002, plus accrued interest from March 31, 2001 to March 31, 2002 at a rate equal to the prime interest rate plus 1.0%.

        In November 2001, a portion of the earn-out payment was paid through the issuance of 9,307 shares of Holdings common stock, valued at $930,700. This consideration paid in partial satisfaction of the earn-out payment was recorded as additional goodwill in the accompanying consolidated financial statements.

        In November 2002, Holdings and the former shareholders of Schmid agreed upon the amount and terms of the remaining unpaid earn-out payment in a negotiated settlement agreement. In settlement of the earn-out payment, Holdings agreed to pay the former Schmid shareholders a total of $2,575,000, plus accrued interest from March 31, 2001 to the final payment date, at a rate of 6.5% per annum. The Company paid $1,200,000 in cash and $300,000 in stock, plus accrued interest of $124,900 and $31,200 in cash and stock, respectively, on November 6, 2002. In addition, the Company paid $358,333 plus accrued interest of $48,524 on January 1, 2003. The remaining accrued earn-out payment was paid in December 2004.

        The total earn-out payment of $2,575,000, interest of $336,700 and costs of $51,000 associated with the Schmid earn-out payment was recorded as additional goodwill related to the Schmid acquisition.

F2-50

(4) Property, Plant, and Equipment

	September 30, 2003
Land	$	373,520
Buildings and improvements		2,568,297
Vehicles and equipment		46,890,666
Furniture and fixtures		553,527
		50,386,010
Less accumulated depreciation		(18,334,531	)
Construction in progress		292,021
	$	32,343,500

        Depreciation expense amounted to $5,757,909 for the nine months ended September 30, 2003. As of September 30, 2003, the Company had capitalized leases of vehicles and equipment with historical costs of $7,124,588 and accumulated amortization of $2,292,105.

        Depreciation expense amounted to $6,192,102 for the nine months ended September 30, 2002. As of December 31, 2002, the Company had capitalized leases of vehicles and equipment with historical costs of $7,124,588 and accumulated amortization of $1,598,295.

        In September 2003, the Company recognized impairment loss in the amount of $5,060,312 related to property, plant, and equipment (See Note 11).

(5) Intangible Assets and Goodwill

        In September 2003, the Company recognized an impairment loss of $13,302,138 related to intangible assets and goodwill. (See Note 11).

(6) Long Term Debt and Capital Lease Obligations

(a) Long-Term Debt

        A summary of Holdings notes payable is as follows:

		September 30, 2003
GE Capital Revolving Credit Facility		$	140,915
GE Capital Term Loan			10,937,500
Equipment notes payable			6,053,720
			17,132,135
Less:
	Current portion of long-term debt		(3,746,980	)
	Current portion of line of credit		(140,915	)
		$	13,244,240

F2-51

        On August 30, 2001, the Company and certain of its subsidiaries entered into a credit agreement ("the Agreement") with General Electric Capital Corporation ("GE Capital") to refinance certain equipment notes payable assumed through the acquisition of the Company's subsidiaries and the funds borrowed from the Company's majority shareholder, First Reserve Fund VIII L.P. (Fund VIII). The Agreement allows for borrowings up to an aggregate sum of $30,000,000, consisting of a Revolving Credit Facility, a Term Loan, an Acquisition Term Loan, a Swing Line Facility and Letters of Credit. All borrowings under the Agreement bear interest at variable interest rates as explained below. The Agreement calls for mandatory prepayments equal to the proceeds from the sale of fixed assets, the proceeds in excess of $250,000 from the sale of Company common stock, and Excess Cash Flow, as defined, beginning in the year ended December 31, 2002. The Agreement is guaranteed by the Company and is secured by all of the Company's personal and real property. Loan origination fees of $1,325,169 were incurred in connection with the Agreement and subsegment refinancing in August of 2002. These fees are included in other assets in the accompanying consolidated balance sheets and are being amortized to interest expense over the terms of the related loans. A commitment fee of 0.5% of the average remaining available borrowings is due monthly.

        Borrowings under the Revolving Credit Facility may be repaid at any time without penalty but must be repaid in full by August 30, 2006; may not exceed $7,500,000; bear interest at either a) the Index Rate, as defined, plus 1.75%, or b) the Company may commit a portion of the outstanding borrowings under the Revolving Credit Facility to one, two or three month terms bearing interest at the LIBOR Rate, as defined, plus 3.25%. The Company is required to pay a monthly commitment fee equal to 0.50% of the remaining funds available under the Revolving Credit Facility.

        Total principal borrowed on August 30, 2001 under the Term Loan was $14,000,000. The Term Loan bears interest at the Company's option of either (a) the Index Rate, as defined, plus 2.00% (6% and 6.25% as of September 30, 2003 and December 31, 2002, respectively) or (b) the LIBOR Rate plus 3.50% (4.61% and 5.26% as of September 30, 2003 and 2002, respectively). Commencing December 31, 2001, accrued interest computed on the outstanding Term Loan balance is due monthly and principal repayments of $437,500 are due quarterly with the remaining principal balance due at August 30, 2006. The Term Loan may be prepaid at any time in the minimum amount of $500,000.

        To the extent that the Company's Borrowing Base, as defined, exceeds that used to determine the initial $30,000,000 credit limit under the Agreement, additional funds will be available to the Company by utilizing the Swing Line Facility. As of September 30, 2003 the Company had no available borrowings under the Swing Line Facility. The Borrowing Base as of September 30, 2003 was $8,126,724.

        The Company may request Letters of Credit from time to time from GE Capital in an amount not to exceed the lesser of $1,000,000 or the funds remaining under the Revolving Credit Facility. Outstanding Letters of Credit bear a fee equal to 3.25% of the outstanding amount. The Company had no Letters of Credit outstanding as of or during the nine months ended September 30, 2003.

        Aggregate indebtedness to GE Capital under the Revolving Credit Facility, Term Loan and Acquisition Term Loan as of September 30, 2003 was $11,078,415, of which substantially all of the balance bears interest at the LIBOR Rate plus 3.5%. The weighted average interest rate for the

F2-52

period these borrowings were outstanding in 2003 and 2002 was 4.79% and 5.42%, respectively. For the nine months ended September 30, 2003 and 2002, total interest expense related to these borrowings was $457,481 and $738,067, respectively.

        On August 30, 2002, the Company amended the Agreement ("Amendment") in conjunction with the reorganization discussed in note 1. The Amendment established the Company as the primary borrower under the Agreement, and removed the Company's subsidiaries as borrowers under the Agreement. No other material changes were made.

        In August 2003, the Company executed a waiver and amendment to the Agreement with GE Capital to cure certain defaults at December 31, 2002, and to loosen certain financial covenant requirements for fiscal 2003 that would have otherwise resulted in a default status.

        The Agreement is subject to various financial and nonfinancial covenants. GE Capital has the option to call the debt in the event of noncompliance with these covenants.

        The Company has entered into various notes for the purchase of equipment and vehicles bearing interest at rates ranging from 0.0% to 8.75% per annum, which mature at various dates from December 2003 to June 2007. These notes are collateralized by related equipment and vehicles.

        At September 30, 2003, aggregate scheduled maturities of long-term debt are as follows:

			GE Capital		Equipment notes	Total
Year ended September 30:
	2004		$	1,750,000	1,996,980	3,746,980
	2005			1,750,000	1,981,207	3,731,207
	2006			7,437,500	1,502,168	8,939,668
	2007			—	573,365	573,365
		Total	$	10,937,500	6,053,720	16,991,220

(b) Capital Lease Obligations

        Holdings has entered into a capital lease obligation for equipment and vehicles. The obligation bears interest at 5.75% per annum and matures January 2006. The lease obligation is collateralized by the related equipment and vehicles which have a net book value of approximately $4,832,483 and $5,526,293 at September 30, 2003 and December 31, 2002, respectively.

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        At September 30, 2003, future minimum payments required under the capital lease obligation follows:

Year ended September 30:
	2004		$	1,413,157
	2005			1,340,438
	2006			537,557
				3,291,152
Less interest				(234,824	)
		Future minimum principal payments		3,056,328
Less current portion				(1,264,688	)
		Long-term portion of capital lease obligations	$	1,791,640

(7) Stockholders' Equity

(a) Common and Preferred Stock

        Holdings is authorized to issue 500,000 shares of $0.001 par value common stock and 500,000 shares of $0.01 par value preferred stock. The rights, terms and conditions of the preferred shares will be determined by the board of directors prior to issuance of any series of preferred stock.

(b) Restricted Shares

        The Company's stock may not be transferred without the consent of the Company. Upon consent by the Company of any share transfers, Fund VIII has a right of first refusal to purchase such shares from the selling shareholder based upon the then fair value of the shares. Furthermore, if greater than 50% of the Company's fully diluted common stock is transferred, any remaining shareholders will be required to transfer their shares to the acquirer.

(c) Stock Options

        The Company's 2000 Stock Option Plan (the "2000 Plan"), provides for the grant of options to purchase up to an aggregate of 21,053 shares of common stock of FESCO by employees and nonemployees; of which 8,990 shares are available for grant as of September 30, 2003. The exercise price of nonqualified options granted is determined by the board of directors based on the estimated fair market value of FESCO common stock at the date of grant. The 2000 Plan allows for option awards to be granted for ten years from the effective date of the plan, which was June 16, 2000, and options granted have a term of ten years. Options vest as determined by the Board.

        FESCO accounts for its stock option plan using the intrinsic value method prescribed by APB Opinion No. 25, Accounting for Stock Issued to Employees. If the Company had elected to

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recognize compensation based upon the calculated fair value of the options, earnings would have been as follows:

		Nine Months Ended September 30,
		2003		2002
As reported:
	Stock-based compensation	$	—	—
	Net loss		14,832,321	3,054,297
Pro forma results:
	Stock-based compensation	$	17,684	17,684
	Net loss		14,850,005	3,071,981

(8) Commitments and Contingencies

(a) Operating Lease Commitments

        The Company has entered into noncancelable operating leases for equipment and real property with lease terms through 2007. Future minimum lease payments at September 30, 2003 are as follows:

September 30:
	2004		$	379,256
	2005			362,844
	2006			292,844
	2007			114,359
		Total minimum payments	$	1,149,303

        Rental expense for the nine months ended September 30, 2003 and 2002 for operating leases was $934,200 and $468,555, respectively.

(b) Employee Retirement Plans

        The Company provides voluntary 401(k) employee savings plans covering all eligible employees (the "401(k) Plan"). Participants in the 401(k) Plan may contribute up to 20% of their eligible compensation. Qualified and nonqualified, discretionary employer contributions may be made by the Company which are allocated to eligible employees based upon their representative share of total compensation paid to eligible employees during the year. Participant and qualified employer contributions vest immediately, whereas nonqualified employer contributions vest ratably until the participant reaches their sixth year of service. During the nine months ended September 30, 2003 and 2002, the Company contributed $112,820 and $126,335, respectively, to the 401(k) Plan.

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(9) Related Parties

        As discussed in note 3, as of September 30, 2003, $848,652 remained accrued for the earn-out obligation and accrued interest to the former Schmid shareholders.

        The Company leases land and buildings from an entity owned by the former owners of Busha. Total rental payments to the entity owned by the former owners of Busha related to this lease was $38,925 in 2003 and $38,100 in 2002 and the monthly rental payments to these entities were $4,160 for first five months of 2002 and $4,325 thereafter.

        Both the former Schmid and Busha shareholders are shareholders of FESCO.

(10) Subsequent Event

Merger

        On October 3, 2003, Basic Energy Services ("Basic") acquired all the capital stock of FESCO. As consideration for the acquisition of FESCO, Basic issued 730,000 shares of its common stock, based on an estimated fair value of the stock of $25.79 per share (a total fair value of approximately $18.8 million), and paid approximately $19.1 million in net cash at the closing to retire debt of FESCO and to pay acquisition costs less 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 preliminary 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

(11) Impairment of Long-Lived Assets

Assets Held and Used

        In September 2003, the Company recorded $5,060,312 of impairment loss in the carrying value of its property, plant, and equipment assets in accordance with Statement of Financial Accounting Standards No. 144 ("SFAS No. 144"). The Company noted indicators during the third quarter of 2003 that the carrying value of its property, plant, and equipment assets may not be recoverable. The impairment analysis was performed in accordance with SFAS No. 144 because of projected declines in current period cash flows combined with a forecast of continuing losses associated with use of the assets and eventual disposal of the assets. The Company evaluated the recoverability of

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its property, plant and equipment assets and recorded impairment losses based on the amounts by which the carrying amount of these assets exceeded their fair values.

        The Company also recorded $13,302,138 of impairment loss in the carrying value of its goodwill and other intangible assets in accordance with Statement of Financial Accounting Standards No 142 ("SFAS 142"). The impairment analysis was performed in accordance with SFAS No. 142 because of projected declines in current period cash flows combined with a forecast of continuing losses associated with use of the assets and eventual disposal of the assets that generated the goodwill. The Company evaluated the recoverability of goodwill and other intangible assets and recorded impairment losses based on the amounts by which the carrying amount of these assets exceeded their fair values. The following table summarizes the components of the impairment loss of long-lived assets:

	September 30, 2003
Property, Plant, and Equipment	$	5,060,312
Intangible assets, net	$	4,003,125
Goodwill		9,299,013
	$	13,302,138

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Report of Independent Registered Public Accounting Firm

The Board of Directors
Basic Energy Services, Inc.:

        We have audited the accompanying combined statement of operations, equity and cash flows of PWI, Inc., PWI Management, LLC, Parker Windham, Ltd., PWI Rentals, L.P., PWI Express Services, L.P., and PWI Disposal, L.P. (collectively referred to herein as "PWI") for the nine months ended September 30, 2003. These combined financial statements are the responsibility of PWI's management. Our responsibility is to express an opinion on these combined financial statements based on our audit.

        We conducted our audit in accordance with auditing standards generally accepted in the United States of America. 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 consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of PWI's internal control over financial reporting. Accordingly, we express no such opinion. 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 audit provides a reasonable basis for our opinion.

        In our opinion, the combined financial statements referred to above present fairly, in all material respects, the combined results of PWI's operations and their cash flows for the nine months ended September 30, 2003, in conformity with accounting principles generally accepted in the United States of America.

        As discussed in Note 2 to the combined financial statements, PWI changed its method of accounting for asset retirement obligations as of January 1, 2003.

/s/ KPMG LLP

Dallas, Texas
August 3, 2005

F3-1

PWI

Combined Statement of Operations

For the Nine Months Ended September 30, 2003

Revenues			$	16,050,084
	Total revenues			16,050,084
Expenses
	Cost of goods sold			9,936,889
	Depreciation, depletion and amortization			2,905,120
	Accretion expense			3,220
	General and administrative expenses			3,320,479
		Total expenses		16,165,708
		Operating loss		(115,624	)
Other income (expense)
	Loss on disposal of assets			(144,666	)
	Other expense			(20,499	)
		Total other income (expense)		(165,165	)
	Loss from continuing operations			(280,789	)
	Cumulative effect of accounting change			(22,871	)
		Net loss	$	(303,660	)

The accompanying notes are an integral part of these financial statements

F3-2

PWI

Combined Statement of Equity

For the Nine Months Ended September 30, 2003

	Equity
Balance at December 31, 2002	$	2,525,619
Distributions		(117,222	)
Net loss		(303,660	)
Balance at September 31, 2003	$	2,104,737

The accompanying notes are an integral part of these financial statements

F3-3

PWI

Combined Statement of Cash Flows

For the Nine Months Ended September 30, 2003

				2003
Cash Flows From Operating Activities
	Net loss			$	(303,660	)
	Adjustments to reconcile net loss to net cash provided by operating activities:
		Depreciation, depletion and amortization			2,905,120
		Accretion expense			3,220
		Loss on sale of assets			144,666
		Cumulative effect of accounting change			22,871
		(Increase) in accounts receivable			(18,458	)
		(Increase) in prepaid assets			(244,827	)
		(Increase) in other assets			(3,869	)
		(Decrease) in accounts payable			(187,234	)
		Increase in other accrued liabilities			489,559
			Net cash provided by operating activities		2,807,388
Cash flows from investing activities
	Additions to property, plant and equipment				(1,390,769	)
	Sales of fixed assets				29,600
			Net cash (used in) investing activities		(1,361,169	)
Cash flows from financing activities
	Proceeds from long-term borrowings				2,333,788
	Principal payments of debt				(3,034,192	)
	Principal payments of capital leases				(628,593	)
	Distributions				(117,222	)
			Net cash (used in) financing activities		(1,446,219	)
			Net increase in cash and cash equivalents		—
			Cash and cash equivalents — beginning of period		—
			Cash and cash equivalents — end of period	$	—
Supplemental disclosure of cash flow information
	Cash paid for interest			$	680,835
	Adoption of SFAS No. 143			$	53,662

The accompanying notes are an integral part of these financial statements

F3-4

PWI

Notes to Combined Financial Statements

September 30, 2003

1.    Nature of Operations and Basis of Presentation

Organization

        The combined financial statements included herein are comprised of the individual financial statements of PWI, Inc., PWI Management, LLC (a limited liability corporation), Parker Windham, Ltd. (a Texas Limited partnership), PWI Rentals, L.P. (a partnership), PWI Express Services, L.P. (a partnership) and PWI Disposal L.P. (a partnership), collectively referred to herein as "PWI." As discussed in Note 8, on October 3, 2003, Basic Energy Services, Inc. acquired substantially all of the assets of PWI. Prior to the acquisition, the PWI entities were under common control.

Nature of Operations

        PWI provides a range of well site services to oil and gas drilling and producing companies, including fluid services, rental services, well site construction services and disposal services. These services are primarily provided by PWI's fleet of equipment. PWI's operations are concentrated in the major United States onshore oil and gas producing regions of the states of Texas and Louisiana.

2.    Summary of Significant Accounting Policies

Principles of Combination

        The accompanying combined financial statements include the accounts of the above named partnerships. All material inter-company transactions and balances have been eliminated in the combination.

Estimates and Uncertainties

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



•

Fair value of assets acquired and liabilities assumed



•

Income taxes



•

Asset retirement obligations

F3-5

Revenue Recognition

        Fluid Services —    Fluid services consist primarily of trucking/transporting and disposal of oil-based and water-based liquids and solids; salt water and brine water used in drilling, production and maintenance of oil and natural gas wells. Parker Windham, Ltd. recognizes revenue when services are performed, collection of the relevant receivables is probable, persuasive evidence of an arrangement exists and the price is fixable and determinable. Parker Windham, Ltd. prices fluid services by the job, by the hour, or by the quantities sold, disposed of or hauled.

        Construction Services —    Construction services consist primarily of site construction (both matted and rocked), lease maintenance, pit closures and roustabout services. PWI Express Services, L.P. recognizes revenue when services are performed, collection of the relevant receivables is probable, persuasive evidence of an arrangement exists and the price is fixable and determinable. PWI Express Services, L.P. prices well site construction services by the hour, day, or project depending on the type of service performed. Long-term well site construction services revenue is recognized based on the percentage of completion method.

        Rental Services —    Rental services consist primarily of rental of equipment to customers for workover, drilling and completion projects including items such as generators, pumps, light towers, open top tanks, frac tanks, cuttings tanks, forklifts, backhoes, Turbo Tanks and hoppers. PWI Rentals, L.P. recognizes revenue when services are performed, collection of the relevant receivables is probable, persuasive evidence of an arrangement exists and the price is fixable and determinable.

        Disposal Services —    Disposal services consist primarily of two land farms and two salt water disposal wells permitted by the Texas Railroad Commission. These land farms and salt water disposal wells are used to dispose of customers' product from customers' locations. PWI Disposal, L.P. recognizes revenue when services are performed, collection of the relevant receivables is probable, persuasive evidence of an arrangement exists and the price is fixable and determinable.

Cash and Cash Equivalents

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

Depreciation, Amortization and Repairs and Maintenance Expense

        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 over the estimated useful lives of the assets.

F3-6

Income Taxes

        Parker Windham, Ltd., the only taxable entity in the combined group, accounts 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.

        No provision for income taxes has been included in these financial statements for any entity other than Parker Windham, Ltd., since the remaining entities are not taxable and the tax effects of their income or loss is passed through to their individual partners.

Concentrations of Credit Risk

        Financial instruments, which potentially subject PWI to concentration of credit risk, consist primarily of temporary cash investments and trade receivables. PWI restricts investment of temporary cash investments to financial institutions with high credit standing. PWI'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. PWI maintains an allowance for potential credit losses on its trade receivables, and such losses have been within management's expectations.

        PWI did not have any one customer which represented 10% or more of combined revenues for the period ended September 30, 2003.

Asset Retirement Obligations

        As of January 1, 2003, PWI adopted Statement of Financial Accounting Standards No. 143, "Accounting for Asset Retirement Obligation" ("SFAS No. 143"). SFAS No. 143 requires PWI to record the fair value of an asset retirement obligation as a liability in the period in which it incurs a legal obligation associated with the retirement of tangible long-lived assets and capitalize an equal amount as a cost of the asset depreciating it over the life of the asset.

        Subsequent to the initial measurement of the asset retirement obligation, the obligation is adjusted at the end of each quarter to reflect the passage of time, changes in the estimated future cash flows underlying the obligation, acquisition or construction of assets, and settlements of obligations. Effective January 1, 2003, PWI recorded additional costs, net of accumulated depreciation of approximately $30,790, an asset retirement obligation of approximately $53,660 and an after-tax charge of approximately $22,871, for the cumulative effect on prior year's depreciation of the additional costs and the accretion expense on the liability related to the expected abandonment costs.

F3-7

        PWI owns and operates salt water disposal sites, brine water wells, gravel pits and land farm sites, each of which is subject to rules and regulations regarding usage and eventual closure. The following table reflects the changes in the liability during the nine months ended September 30, 2003:

Balance, January 1, 2003	$	—
Initial recognition of asset retirement obligation		53,662
Accretion expense		3,220
Balance, September 30, 2003	$	56,882

Environmental

        PWI 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 PWI 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.

3.    Income Taxes

        No federal income taxes were paid or received in the period ended September 30, 2003.

        The income tax provision differs from the amount of income tax determined by applying the U.S. federal income tax rate to pre-tax income (loss) due to the following:

	Nine Months Ended September 30, 2003
Income tax expense (benefit) at statutory rate	$	(103,244	)
Income of non-taxable partnerships at statutory rate		(190,009	)
Non-deductible expenses and other		14,448
Valuation allowance		278,805
Income tax expense	$	—

        A valuation allowance is provided when it is more likely than not that some portion of the deferred tax assets will not be realized. Based on expectations for the future and the availability of certain tax planning strategies that would generate taxable income to realize the net tax benefits, if implemented, management has determined that it is more likely than not that a portion of the deferred tax assets will not be realized. Based on recurring operating losses of Parker Windam, Ltd., management has determined a valuation allowance is required to reduce net deferred tax assets to zero at December 31, 2002 and September 30, 2003.

F3-8

4.    Commitments and Contingencies

Environmental

        PWI is subject to various federal, state and local environmental laws and regulations that establish standards and requirements for protection of the environment. PWI cannot predict the future impact of such standards and requirements which are subject to change and can have retroactive effectiveness. PWI continues to monitor the status of these laws and regulations. Management does not believe that the disposition of any of these items will result in a material adverse impact to PWI's financial position, liquidity, capital resources or future results of operations.

        Currently, PWI 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 PWI 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 PWI'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, PWI is a party to litigation or other legal proceedings that PWI considers to be a part of the ordinary course of business. PWI is not currently involved in any legal proceedings that could reasonably be expected to have a material adverse effect on its financial condition, results of operations or liquidity.

Operating Leases

        PWI 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 September 30, 2003, the future minimum lease payments under non-cancelable operating leases are as follows:

Twelve Months Ended September 30,
2004	$	224,208
2005	$	61,090

        Rent expense for the nine months ended September 30, 2003 approximated $49,095, which includes certain related party transactions (see footnote 5).

Employment Agreements

        PWI has entered into employment agreements with various employees that range in terms up through October, 2004. Under these agreements, if the employee is terminated for certain reasons, he would be entitled to his regular pay and all benefits through the date of his termination of employment. If the employee is terminated without cause, then he would be entitled to the continued receipt of his base salary and benefits until the end of the term of the agreement.

F3-9

5.    Related Party Transactions

        PWI leased certain yards owned by a related party for approximately $3,000 for the nine months ended September 30, 2003. PWI also leased a certain office building owned by a related party for approximately $19,995 for the nine months ended September 30, 2003. PWI had notes payable to these related parties for approximately $514,000 at September 30, 2003.

6.    Profit Sharing Plan

        PWI 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. PWI 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 $32,304 in 2003.

7.    Business Segment Information

        PWI's reportable business segments are: fluid services, rental services, well site construction services and disposal services. The following is a description of the segments:

        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. These assets 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.

        Rental Services:    This segment is involved in the rental of equipment for their locations. Rental equipment includes items such as generators, pumps, light towers, open top tanks, frac tanks, cuttings tanks, forklifts, backhoes, TurboTanks, and hoppers.

        Well Site Construction Services:    This segment utilizes a fleet of power units, dozers, trenchers, motor graders, backhoes and other heavy equipment. These assets 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.

        Disposal Services:    This segment includes two land farms and two salt water disposal sites permitted by the Texas Railroad Commission which are used for the actual disposal of product(s) from workover, drilling and completion sites as well as the separation, storage and sale of skim oil from the disposal facility.

        PWI'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

F3-10

capital and debt financing costs. The following table sets forth certain financial information with respect to our reportable segments:

	Fluid Services			Rental Services			Well Site Construction Services			Disposal Services			Corporate and Other		Total
Operating Revenues	$	10,397,549		$	2,810,912		$	2,616,140		$	225,483		$	—	$	16,050,084
Direct Operating Costs		(7,379,618	)		(874,733	)		(1,666,955	)		(15,583	)	$	—		9,936,889
Segment Profits	$	3,017,931		$	1,936,179		$	949,185		$	209,900		$	—	$	6,113,195
Capital Expenditures (Excluding Acquisitions)	$	1,114,560		$	23,336		$	14,141		$	10,116		$	228,617	$	1,390,770
Identifiable Assets	$	5,358,651		$	3,135,170		$	2,459,181		$	251,146		$	568,502	$	11,772,650

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

	Nine months ended September 30, 2003
Segment profits	$	6,113,195
General and administrative expenses		(3,320,479	)
Depreciation and amortization		(2,908,340	)
Operating loss	$	(115,624	)

8.    Subsequent Events

        On October 3, 2003, Basic Energy Services, Inc. acquired substantially all the assets of PWI for $25.1 million plus a $2.5 million contingent earn-out payment. The contingent earn-out payment will be paid upon the PWI assets meeting certain financial objectives in the future. The cash cost of this 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.

F3-11

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.

        Frac job or fracturing operations:    A procedure to stimulate production of oil or gas from a well by pumping fluids from the surface under high pressure into the wellbore to induce fractures in the formation.

        Frac tank:    A steel tank used to store fluids at the well location to facilitate completion and workover operations. The largest demand is related to the storage of fluid used in fracturing operations.

        Hot oil truck:    A truck mounted pump, tank and heating element used to melt paraffin accumulated in the well bore by pumping heated oil or water through the well.

        Newbuild:    A newly built rig, as compared to a refurbished rig that may contain substantially all new components or new derrick but utilizes an older frame.

        Plugging and abandonment activities:    Activities to remove production equipment and seal off a well at the end of a well's economic life.

        Slickline.    A form of wireline that lacks an electrical conduit and is used only to perform mechanical tasks such as setting or retrieving various tools.

        Stimulation:    The general process of improving well productivity through fracturing or acidizing operations.

        Swab rig:    Truck mounted equipment consisting of a hoist and mast used to remove, or "swab," wellbore fluids by alternatively lowering and raising tools in a well's tubing or casing.

        Underbalanced drilling:    A technique that involves maintaining the pressure in a well at or slightly below that of the surrounding formation using air, nitrogen, mist, foam or lightweight drilling fluids instead of conventional drilling fluid.

A-1

        Water cut:    The volume of water produced by a well as a percentage of all fluids produced.

        Wellbore:    The drilled hole of a well, which may include open hole or uncased portions, and which may also refer to the rock face that bounds the inside diameter of the wall of the drilled hole.

        Well completion:    The activities and procedures necessary to prepare a well for the production of oil and gas after the well has been drilled to its targeted depth. Well completions establish a flow path for hydrocarbons between the reservoir and the surface.

        Well servicing:    The maintenance work performed on an oil or gas well to improve or maintain the production from a formation already producing. It usually involves repairs to the downhole pump, rods, tubing, and so forth or removal of sand, paraffin or other debris which is preventing or restricting production of oil or gas.

        Well workover:    Refers to a broad category of procedures preformed on an existing well to correct a major downhole problem, such as collapsed casing, or to establish production from a formation not previously produced, including deepening the well from its originally completed depth.

        Wireline:    A general term used to describe well-intervention operations conducted using single-strand or multistrand wire or cable for intervention in oil or gas wells. Although applied inconsistently, the term is used commonly in association with electric logging and cables incorporating electrical conductors See "slickline" and "electric wireline" for specific types of wireline services.

A-2

        Until             , 2005 (25 days after the commencement of the offering), all dealers that effect transactions in these securities, whether or not participating in this offering, may be required to deliver a prospectus. This is in addition to the dealers' obligation to deliver a prospectus when acting as an underwriter and with respect to unsold allotments or subscriptions.

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.

                  Shares

Basic Energy Services, Inc.

Common Stock

PROSPECTUS

               , 2005

Goldman, Sachs & Co.

Credit Suisse First Boston

Lehman Brothers
UBS Investment Bank
Deutsche Bank Securities
Raymond James
RBC Capital Markets

PART II

INFORMATION NOT REQUIRED IN PROSPECTUS

ITEM 13. Other Expenses of Issuance and Distribution

        Set forth below are the expenses (other than underwriting discounts and commissions) 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		$	33,839
NASD filing fee			29,250
NYSE listing fee			170,000
Printing and engraving expenses			400,000
Legal fees and expenses			250,000
Accounting fees and expenses			350,000
Transfer agent and registrar fees			4,500
Miscellaneous			462,411
	TOTAL	$	1,700,000

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

II-1

Energy Services shall have no personal liability to Basic Energy Services or its stockholders for monetary damages for breach of fiduciary duty as a director, except (1) for any breach of the director's duty of loyalty to Basic Energy Services or its stockholders, (2) for acts or omissions not in good faith or which involve intentional misconduct or knowing violation of 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.

        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.

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

II-2

or given directly or indirectly. The following information gives effect to a 5-for-1 stock split effected as a stock dividend on September 26, 2005:

        In February 2002, our predecessor, Basic Energy Services, Inc., 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 existing stockholders and their affiliates for aggregate cash consideration of $12,000,000.

        On June 25, 2002, our predecessor, Basic Energy Services, Inc., issued 150,000 shares of our Series A 10% Cumulative Preferred Stock, together with warrants exercisable for an aggregate of 3,750,000 shares of our common stock, to existing stockholders and their affiliates for aggregate cash consideration of $15,000,000. Offering expenses related to this transaction totaled $58,000.

        On January 24, 2003, we issued one share of our common stock in exchange for each share of then-outstanding common stock of our predecessor, Basic Energy Services, Inc., and shares of our Series A 10% Cumulative Preferred Stock in exchange for all of the then-outstanding shares of its Series A 10% Cumulative Preferred Stock, and assumed all of the outstanding warrants and options then outstanding by this predecessor.

        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 May 5, 2003, we granted options to purchase an aggregate of 605,000 shares of common stock under our Amended and Restated 2003 Incentive Plan to employees and directors at an exercise price of $4.00 per share. We received no payments from the optionees upon issuance of the options.

        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.

        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 $5.1584 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.

II-3

        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 May 16, 2005, we granted options to purchase an aggregate of 5,000 shares of common stock under our Amended and Restated 2005 Incentive Plan to employees at an exercise price of $6.98.

ITEM 16. Exhibits and Financial Statement Schedules

a.

Exhibits:

1.1	—	Form of Underwriting Agreement
3.1**	—	Amended and Restated Certificate of Incorporation dated as of September 22, 2005
3.2**	—	Form of Amended and Restated Bylaws
4.1*	—	Specimen Stock Certificate representing common stock
5.1*	—	Opinion of Andrews Kurth LLP
10.1**	—	Form of Indemnification Agreement
10.2**	—	Employment Agreement dated as of March 1, 2004 with Kenneth V. Huseman
10.3**	—	Employment Agreement dated as of May 1, 2003 with Dub W. Harrison
10.4**	—	Employment Agreement dated as of May 1, 2003 with Charles W. Swift
10.5**	—	Employment Agreement dated as of May 1, 2003 with James J. Carter
10.6**	—	Employment Agreement dated as of January 26, 2005 with Alan Krenek
10.7**	—	Second Amended and Restated Stockholders' Agreement dated as of April 2, 2004 by and among Basic Energy Services, Inc. and the stockholders listed therein
10.8**	—	Stock Purchase Agreement dated as of September 18, 2003, as amended on October 1, 2003, with FESCO Holdings, Inc. and the sellers named therein
10.9**	—	Asset Purchase Agreement dated as of August 14, 2003 with PWI
10.10**	—	Second Amended and Restated Credit Agreement, dated as of October 3, 2003, restated as of December 21, 2004, by and among Basic Energy Services, L.P. and the other Borrowers named therein, Basic Energy Services, Inc. and the other Guarantors named therein, the Lenders party thereto, UBS Securities LLC as Arranger, Hibernia National Bank, as Documentation Agent, and UBS AG, Stanford Branch, as Issuing Bank, Administrative Agent and Collateral Agent
10.11**	—	Second Amended and Restated 2003 Incentive Plan

II-4

10.12**	—	Form of Non-Qualified Option Grant Agreement (Executive Officer — Pre-March 1, 2005)
10.13**	—	Form of Non-Qualified Option Grant Agreement (Executive Officer — Post-March 1, 2005)
10.14**	—	Form of Non-Qualified Option Grant Agreement (Non-Employee Director — Pre-March 1, 2005)
10.15**	—	Form of Non-Qualified Option Grant Agreement (Non-Employee Director — Post-March 1, 2005)
10.16**	—	Form of Restricted Stock Grant Agreement
10.17*	—	Workover Unit Package Contract and Acceptance Agreement, dated as of May 17, 2005, by and between Basic Energy Services, Inc. and Taylor Rigs, LLC
10.18**	—	Share Exchange Agreement dated as of September 22, 2003, by and among BES Holding Co. and the Stockholders named therein.
10.19*	—	Form of Share Tender and Repurchase Agreement
21.1*	—	Subsidiaries of Basic Energy Services
23.1*	—	Consent of KPMG LLP
23.2*	—	Consent of PricewaterhouseCoopers LLP
23.3*	—	Consent of Andrews Kurth LLP (Contained in Exhibit 5.1)
24.1**	—	Power of Attorney

*

Filed herewith

**

Previously filed

II-5

b.

Financial Statement Schedules

        None.

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)   To provide to the underwriter(s) at the closing specified in the underwriting agreements, certificates in such denominations and registered in such names as required by the underwriter(s) to permit prompt delivery to each purchaser.

        (c)   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.

        (d)   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 Amendment No. 2 to 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 November 4, 2005.

BASIC ENERGY SERVICES, INC.
By:	/s/  KENNETH V. HUSEMAN
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
/s/  KENNETH V. HUSEMAN Kenneth V. Huseman	President, Chief Executive Officer and Director (Principal Executive Officer)	November 4, 2005
/s/  ALAN KRENEK Alan Krenek	Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer)	November 4, 2005
/s/  STEVEN A. WEBSTER * Steven A. Webster	Chairman of the Board	November 4, 2005
/s/  JAMES S. D'AGOSTINO, JR. * James S. D'Agostino, Jr.	Director	November 4, 2005
/s/  WILLIAM E. CHILES * William E. Chiles	Director	November 4, 2005
/s/  ROBERT F. FULTON * Robert F. Fulton	Director	November 4, 2005
/s/  SYLVESTER P. JOHNSON, IV * Sylvester P. Johnson, IV	Director	November 4, 2005
/s/  H.H. WOMMACK, III * H.H. Wommack, III	Director	November 4, 2005

*By:
/s/  ALAN KRENEK Alan Krenek
As Attorney-in-Fact

II-7

EXHIBIT INDEX

1.1	—	Form of Underwriting Agreement
3.1**	—	Amended and Restated Certificate of Incorporation dated September 22, 2005
3.2**	—	Form of Amended and Restated Bylaws
4.1*	—	Specimen Stock Certificate representing common stock
5.1*	—	Opinion of Andrews Kurth LLP
10.1**	—	Form of Indemnification Agreement
10.2**	—	Employment Agreement dated as of March 1, 2004 with Kenneth V. Huseman
10.3**	—	Employment Agreement dated as of May 1, 2003 with Dub W. Harrison
10.4**	—	Employment Agreement dated as of May 1, 2003 with Charles W. Swift
10.5**	—	Employment Agreement dated as of May 1, 2003 with James J. Carter
10.6**	—	Employment Agreement dated as of January 26, 2005 with Alan Krenek
10.7**	—	Second Amended and Restated Stockholders' Agreement dated as of April 2, 2004 by and among Basic Energy Services, Inc. and the stockholders listed therein
10.8**	—	Stock Purchase Agreement dated as of September 18, 2003, as amended on October 1, 2003, with FESCO Holdings, Inc. and the sellers named therein
10.9**	—	Asset Purchase Agreement dated as of August 14, 2003 with PWI
10.10**	—	Second Amended and Restated Credit Agreement, dated as of October 3, 2003, restated as of December 21, 2004, by and among Basic Energy Services, L.P. and the other Borrowers named therein, Basic Energy Services, Inc. and the other Guarantors named therein, the Lenders party thereto, UBS Securities LLC as Arranger, Hibernia National Bank, as Documentation Agent, and UBS AG, Stanford Branch, as Issuing Bank, Administrative Agent and Collateral Agent
10.11**	—	Second Amended and Restated 2003 Incentive Plan
10.12**	—	Form of Non-Qualified Option Grant Agreement (Executive Officer — Pre-March 1, 2005)
10.13**	—	Form of Non-Qualified Option Grant Agreement (Executive Officer — Post-March 1, 2005)
10.14**	—	Form of Non-Qualified Option Grant Agreement (Non-Employee Director — Pre-March 1, 2005)
10.15**	—	Form of Non-Qualified Option Grant Agreement (Non-Employee Director — Post-March 1, 2005)
10.16**	—	Form of Restricted Stock Grant Agreement
10.17*	—	Workover Unit Package Contract and Acceptance Agreement, dated as of May 17, 2005, by and between Basic Energy Services, Inc. and Taylor Rigs, LLC
10.18**	—	Share Exchange Agreement dated as of September 22, 2003, by and among BES Holding Co. and the Stockholders named therein.
10.19*	—	Form of Share Tender and Repurchase Agreement
21.1*	—	Subsidiaries of Basic Energy Services
23.1*	—	Consent of KPMG LLP
23.2*	—	Consent of PricewaterhouseCoopers LLP
23.3*	—	Consent of Andrews Kurth LLP (Contained in Exhibit 5.1)
24.1**	—	Power of Attorney

*

Filed herewith

**

Previously filed

EX-4.1

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Exhibit 4.1

SPECIMEN STOCK CERTIFICATE REPRESENTING COMMON STOCK
(FRONT)

NUMBER		SHARES
	(BASIC ENERGY SERVICES, INC. LOGO)
BAS
THIS CERTIFICATE IS TRANSFERABLE IN NEW YORK, NY		COMMON STOCK INCORPORATED UNDER THE LAWS OF THE STATE OF DELAWARE
	BASIC ENERGY SERVICES, INC.
		CUSIP 06985P 10 0 SEE REVERSE FOR CERTAIN RESTRICTIONS
THIS CERTIFIES THAT IS THE RECORD HOLDER OF
FULLY PAID AND NON-ASSESSABLE SHARES OF COMMON STOCK, PAR VALUE $.01, OF BASIC ENERGY SERVICES, INC.

transferable on the books of the Corporation by the holder hereof in person or by duly authorized attorney, upon surrender of this Certificate properly endorsed. This Certificate and the shares represented hereby are issued and shall be held subject to all of the provisions of the Certificate of Incorporation of the Corporation and all amendments thereto, to all of which the holder, by acceptance hereof, assents. This Certificate is not valid until countersigned and registered by the Transfer Agent and Registrar.

        Witness the facsimile seal of the Corporation and the facsimile signatures of its duly authorized officers.

Dated:

/s/ James J. Carter EXECUTIVE VICE PRESIDENT	(CORPORATE SEAL)	/s/ Kenneth V. Huseman PRESIDENT AND CHIEF EXECUTIVE OFFICER	COUNTERSIGNED AND REGISTERED: AMERICAN STOCK TRANSFER & TRUST COMPANY (New York, N.Y.)
			TRANSFER AGENT AND REGISTRAR
			BY
			AUTHORIZED SIGNATURE

(REVERSE)

BASIC ENERGY SERVICES, INC.

        The Corporation will furnish to any stockholder upon request and without charge a full statement of the designations, preferences, conversion and other rights, voting powers, restrictions, limitations as to dividends, qualifications, and terms and conditions of redemption of shares of each class authorized to be issued and, with respect to the classes of shares which may be issued in series, the differences in the relative rights and preferences between the shares of each series, to the extent they have been set. Such request may be made to the Secretary of the Corporation at its principal office or to the Transfer Agent.

KEEP THIS CERTIFICATE IN A SAFE PLACE. IF IT IS LOST, STOLEN, MUTILATED OR DESTROYED, THE CORPORATION WILL REQUIRE A BOND OF INDEMNITY AS A CONDITION TO THE ISSUANCE OF A REPLACEMENT CERTIFICATE.

        The following abbreviations, when used in the inscription on the face of this certificate, shall be construed as though they were written out in full according to applicable laws or regulations:

TEN COM	—	as tenants in common	UNIF GIFT/TRANS MIN ACT—	(Cust)	CUSTODIAN	(Minor)
TEN ENT	—	as tenants by the entireties
JT TEN	—	as joint tenants with right of survivorship and not as tenants in common		under Uniform Gifts/Transfers to Minors Act
				(State)

Additional abbreviations may also be used though not in the above list.

FOR VALUE RECEIVED, HEREBY SELLS, ASSIGNS AND TRANSFERS UNTO

PLEASE INSERT SOCIAL SECURITY OR OTHER
IDENTIFYING NUMBER OF ASSIGNEE

(Please Print or Typewrite Name and Address, Including Zip Code, of Assignee)

	shares
of the Common Stock represented by the within Certificate, and do hereby irrevocably constitute and appoint

	Attorney
to transfer the said shares on the books of the within named Corporation with full power of substitution in the premises.

Dated
	NOTICE: The Signature(s) To This Assignment Must Correspond With The Name(s) As Written Upon The Face Of The Certificate In Every Particular, Without Alteration Or Enlargement Or Any Change Whatever.

SIGNATURE(S) GUARANTEED:
	THE SIGNATURE(S) MUST BE GUARANTEED BY AN ELIGIBLE GUARANTOR INSTITUTION (BANKS, STOCKBROKERS, SAVINGS AND LOAN ASSOCIATIONS AND CREDIT UNIONS WITH MEMBERSHIP IN AN APPROVED SIGNATURE GUARANTEE MEDALLION PROGRAM), PURSUANT TO S.E.C. RULE 17Ad-15.

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Exhibit 4.1

EX-5.1

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Exhibit 5.1

November 4, 2005

Basic Energy Services, Inc.
400 W. Illinois, Suite 800
Midland, Texas 79701

Ladies and Gentlemen:

        We have acted as counsel to Basic Energy Services, Inc., a Delaware corporation (the "Company"), in connection with the preparation and filing of the Registration Statement on Form S-1 (File No. 333-127517), as amended (the "Registration Statement"), filed with the Securities and Exchange Commission (the "Commission") pursuant to the Securities Act of 1933, as amended (the "Securities Act"), in connection with the public offering of up to 14,375,000 shares (including shares to be issued upon exercise of the underwriters' over-allotment options) (the "Shares") of the Company's common stock, par value $0.01 per share ("Common Stock"), proposed to be offered by the Company and the selling stockholders under the Registration Statement. This opinion also relates to any registration statement of the Company relating to the registration of additional shares of Common Stock pursuant to Rule 462(b) under the Securities Act.

        We have examined originals or copies of (i) the Registration Statement, including the form of prospectus included therein, (ii) the Amended and Restated Certificate of Incorporation of the Company filed with the Secretary of State of the State of Delaware on September 22, 2005, (iii) the Bylaws of the Company as in effect on the date hereof, and certain amendments to be effective with respect thereto upon the consummation of the offering of the Shares, (iv) certain resolutions of the Board of Directors of the Company and committees thereof and (v) such other documents and records as we have deemed necessary and relevant for purposes hereof. We have relied upon certificates of public officials and officers of the Company as to certain matters of fact relating to this opinion and have made such investigations of law as we have deemed necessary and relevant as a basis hereof. We have not independently verified any factual matter relating to this opinion.

        We have assumed and have not verified (i) the genuineness of all signatures on all documents that we have examined, (ii) the legal capacity of all natural persons, (iii) the authenticity of all documents submitted to us as originals, and (iv) the conformity to the authentic originals of all documents supplied to us as certified or photostatic or faxed copies.

Basic Energy Services, Inc.
November 4, 2005
Page 2

        Based upon the foregoing, and subject to the limitations and assumptions set forth herein, and having due regard for such legal considerations as we deem relevant, we are of the opinion that (i) the issuance of the Shares in accordance with the Registration Statement has been duly authorized by the Company and (ii) the Shares, when thereafter issued against payment therefor in connection with the offering of such Shares, will be validly issued, fully paid and non-assessable.

        We express no opinion other than as to the federal laws of the United States of America and the Delaware General Corporation Law (which is deemed to include the applicable provisions of the Delaware Constitution and reported judicial opinions interpreting those laws).

        We consent to the filing of this opinion as an exhibit to the Registration Statement, and we further consent to the use of our name under the caption "Legal Matters" in the Registration Statement and the prospectus which forms a part thereof. In giving these consents, we do not thereby admit that we are within the category of persons whose consent is required under Section 7 of the Securities Act or the rules and regulations issued thereunder. This opinion may be incorporated by reference in a registration statement by the Company relating to the registration of additional shares of Common Stock pursuant to Rule 462(b) under the Securities Act, in which case the opinion expressed herein will apply to the additional shares registered thereunder. Our opinion is rendered as of the date hereof, and we assume no obligation to update or supplement our opinion to reflect any change of fact, circumstance or law after such time as the Registration Statement is declared effective.

Very truly yours,

/s/ Andrews Kurth LLP

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Exhibit 5.1

EX-10.17

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Exhibit 10.17

(Taylor Logo)

1045 Keystone Avenue	Phone:	(918) 266-7301
Tulsa Port of Catoosa	Fax:	(918) 266-5223
Catoosa, OK 74015	sales@taylorrigs.com

C500 WORKOVER UNIT PACKAGE

Contract & Acceptance Agreement: CP-05-023
Prepared for

Mr. Dub Harrison
Basic Energy Service
P.O. Box 10460
Midland, TX 79702

DATE: May 17, 2005

TABLE OF CONTENTS

SECTION 1—GENERAL DESCRIPTION	p. 3 SECTION 2—
ENVIRONMENTAL PARAMETERS	p. 4 SECTION 3—
TECHNICAL SPECIFICATIONS	p. 5 SECTION 4—
ACCESSORIES	p. 12 SECTION 5—
RIG OPTIONS	p. 13 SECTION 6—
RIG SPARES	p. 14 SECTION 7—
DELIVERY & COMMISSIONING	p. 15 SECTION 8—
DOCUMENTATION	p. 16 SECTION 9—
WARRANTY	p. 17 SECTION 10
—PRICING	p. 19 SECTION 11
—TERMS & CONDITIONS	p. 20 SECTION 12
—RESALE PARTS AGREEMENT	p. 22 SECTION 13
—CONTRACT ACCEPTANCE	p. 23 APPENDIX A
—PAYMENT & DELIVERY SCHEDULE	p. 24

2

SECTION 1—GENERAL DESCRIPTION

The Taylor C500 Workover Unit is a heavy-duty service package mounted on a 5-axle off-road carrier. The unit is comprised of a carrier, power package, rawworks, and mast. The package is for highly mobile land operations.

The rig carrier is a proprietary design manufactured by Taylor Rigs. The carrier has 5 axles with 4 driving hubs. Axle location is specifically engineered for optimum weight distribution, minimal turning radius, and heavy-duty off-road operations.

The power package is comprised of (1) one 475 hp diesel engine with automatic transmission. The engine and transmission combination has been reviewed by the component manufacturers for correct application and installation.

The unit includes a DD260 drawworks package. The innovative package is lightweight and provides exceptional strength and performance. The drawworks has full disc brakes, heavy-duty right angle box, and full guards and covers. The drawworks is designed for ease of service and maintenance. Taylor utilizes "off the shelf" bearings and seals for reduced cost and ease of availability, and simplified one-step brake adjustment. Drawworks features remote bearing lubrication for fast service and outboard clutches for ease of accessibility and increased cooling performance.

The 104 ft. (31.7m), 240,000lb (109 MT) mast is a telescoping design, manufactured in accordance with API and Taylor Rigs strict quality control processes. The mast includes an automatic racking board and telescopes hydraulically.

The rig will be supplied with all equipment listed in this contract and designed to operate in the environment described in Section 2 of this contract.

IMPORTANT NOTE: All Taylor contracts are prepared based on information provided by the customer, broker, or other source. Unless specified, this contract may not contain all equipment or fools required to complete a specific job.

Due to the complex and varied configurations, Taylor Rigs, LLC equipment omitted from this contract.

3

SECTION 2—ENVIRONMENTAL PARAMETERS

Equipment listed in this contract will meet or exceed the following operating parameters:

2.1 TEMPERATURE
	Minimum Ambient Operating	- -20 C (-4 F)
	Maximum Ambient Operating	46 C (115 F)
2.2 HUMIDITY
	Max Relative	<90%
2.3 VIBRATION I SHOCK
	Maximum Shock Load	1g
2.4 LOCATION
	Location	Inland
	Conditions	Non-Desert / Non-Arctic

4

SECTION 3—BASE RIG

3.1   DD260 DRAWWORKS:

3.1.1

OVERALL

Double Drum Drawworks, with a 41,500-lb. main drum single line pull on a bare drum in 1^st gear. Innovative drive design eliminates all live chains, reduces moving parts, and reduces weight. All Taylor drawworks meet or exceed API recommendation for design criteria and are engineered to meet a minimum 4:1 safety factor.

All drawworks bearings, seals and chains are off-the-shelf items and may be purchased directly from the factory or from parts distributors worldwide.

3.1.2

SPECIFICATIONS

DD260 Main Drum:
Main Barrel Dimensions	18.75 in. x 34 in. (476 mm x 864mm)
Wireline Size	1" in. (25.4 mm)
Drum Clutch	14 in. (356 mm) 3-Plate
Drawworks Speeds	6 Forward, 1 Reverse
Input Drive Line	1710 Spicer
Drum Drive Chain	Single 140
Brake System	Dual Disc—60 in. x 4 in. x 10 in.
Brake Cooling	Air
DD260 Sand Drum:
Sandline Drum Diameter	12.75 in. (324 mm.)
Standard Sandline Size	9/16 in. (14.3 mm.)
Capacity	16,000 ft. (4,877 m.)
Sandline Drum Clutch	14 in. (356 mm.) 2-Plate
Drum Drive Chain	Single 140
Brake System	Single Disc—48 in. x 4 in. x 7 in.
Brake Cooling	Air

3.1.3

DRAWWORKS FRAME

The DD260 frame is a mild steel structure utilizing structural material and one-piece in. drawworks side plates.

3.1.4

DRUMS

Wide barrel design reduces line interference when running double fast line. Taylor's exclusive spool drum design reduces drumshaft flex and weight while increasing total strength. Tubing drum has Lebus grooving with turn back and kick plates to reduce line wear and assist in spooling.

3.1.5

BRAKE SYSTEM

Air cooled Disc with air activation system.

3.1.6

DRUM CLUTCH

Wichita brand air clutch mounted outboard of drawworks frame and chain case. Mounted on lower output shaft. Taylor's exclusive use of the clutch on the lower shaft reduces required clutch size, air requirements and eliminates all live chains.

5

3.1.7

CHAIN DRIVES

Diamond 140 chain, oil bathed for long life. Chain is fully enclosed in a one-piece chain case with a gasket flange. The design prevents case leakage due to warping. Access panel provides for chain maintenance and removal without removing the chain case.

3.1.8

POWER DRIVE

The DD260 right angle gearbox utilizes a commercially manufactured Eaton(5) gear assembly or "third member". The third member is mounted in a fabricated steel housing and located in the drawworks frame. The package is rated for a maximum input of 700 hp. Taylor's design allows right angle box to be serviced by any Eaton(5) service center or technician with "off-the-shelf" components.

3.1.9

OPERATORS CONSOLE

The operators console include brake levers, clutch, engine throttle, and emergency shutdown. The console is located behind the drawworks frame, near the mast base, for excellent drum visibility and operator comfort.

3.1.10

LUBRICATION

Remote bearing lubrication with return lines. Lubrication system ensures complete lubrication of drum bearings. Return lines for grease provides for visual confirmation of complete lubrication. Lubrication points are conveniently located outside the drawworks frame for ease of maintenance.

3.1.11

AUXILIARY HOIST

Hydraulic "planetary" style hoist mounted on the rig deck. Hoist capacity is 7,000 lbs. (3.1 mt) and comes with 250'(61 m) of in. wire line with tail chain.

3.2   TELESCOPING MAST:

3.2.1

OVERALL

A telescoping mast with open face mast design, manufactured to API 4-F specifications. The open face design utilizes structural steel construction, which allows for maximum block clearance. Mast includes a ladder from rig floor to crown and a block cradle.

3.2.2

SPECIFICATIONS

Mast Height:		104' (31.7 m)
No. Of Lines to Block		4, 6, or 8
API Capacity
	4-Lines	200,000 lbs. (90.7 mt)
	6-Lines	225,000 lbs. (102 mt)
	8-Lines	240,000 lbs. (108.9 mt)
Drilling Line Size:		1 in. (25.4 mm.)
Racking Board Height		55.7 ft. (17 m), 66.7 ft. (20.2 m),
Racking Board Capacity
	2-7/8 in EUE	24,120 ft. (7,351.7 m)
	3-1/2 in. DP	13,680 ft. (4,169.5 m)
	4-1/2 in. DP	6,480 ft. (1,975.8 m)
	Rod Basket Height	78 ft. 7 in. (23.9 m)

3.2.3

BASE SECTION

Four Leg style base section hinged to carrier frame. (2) Turnbuckles attached from top of mast base to carrier frame allow for mast angle adjustment. The well-side mast legs have manual screw jacks.

6

3.2.4

LOWER SECTION

3 in x 6 in x 1/4 in (76.2 mm x 152.4 mm x 6.35 mm) rectangular tubing main legs, with 1-1/2 in x 3 in x 1-1/8 in (38.1 mm x 76.2 mm x 22.57 mm) "C" braces. Lower section of mast hinges to top of mast base and rests on headache rack during transport.

3.2.5

UPPER SECTION

Rectangular tubing construction. 3 in x 6 in x 1/4 in (76.2 mm x 152.4 mm x 6.35 mm) rectangular tubing upper legs, with 1-1/2 in x 3 in x 1-1/8 in (38.1 mm x 76.2 mm x 22.57 mm) "C" braces. Upper section rests inside lower section until mast is raised. Upper section then telescopes hydraulically upward from lower section and locks in place with spring deployed latching pins.

3.2.6

STAND PIPE

One (1) 2 7/8" double height stand pipe x 5000 psi mounted in derrick. Stand pipe includes all necessary brackets and complete installation. Top and bottom to be equipped with hammer union and 180 degree upper end.

3.2.7

CROWN BLOCK

Crown block is set up for a 4, 6, or 8 line string-up. Crown sheaves are steel and grooved for 1 in (25.4 mm) wire line. All sheaves are mounted on tapered roller bearings with grease zerts for ease of maintenance.

Crown includes: (1) one 24 in (610 mm) fast line sheave, (3) three 24 in (610 mm) crossover sheaves, and (1) one 30 in (762 mm) sandline sheave. Crown will also include extended post on ladder side for mounting of fall protection device.

3.2.8

RACKING BOARD AND ROD BASKET

The mast includes an all welded racking board. The racking board automatically deploys as the mast is extended. Tubing board height is two positions and includes adjustable fingers for end racking of tubing.

The mast includes an automatically deploying rod basket with rod hangers and air transfer system. Please note if using fiberglass rods.

3.2.9

MAST RAISING SYSTEM

The mast utilizes two, 3-stage, double acting raising rams and a single, single-stage telescoping cylinder. Raising and telescoping controls are located near the operator's console for easy access and operation. Hydraulic pressure gauges are mounted on the mast base to provide system monitoring during the raising/lowering process. The hydraulic system incorporates a safety choke system to control flow to telescoping or raising cylinders due to a hydraulic line rupture or damage.

3.2.10

GUYLINES

Mast includes (2) load guys from the crown to carrier and (1) set of wind guys that meet or exceed API specifications.

3.2.11

DEADLINE ANCHOR

Deadline anchor is designed and manufactured in accordance with API specifications and rated for a 50,000-lbs. maximum deadline load. Located on off operators side of rig float and comes with line clamp.

7

3.2.12

FOLDING WORK PLATFORM

Includes (1) 8 ft. wide x 6 ft. long folding work platform with 2' wings on each side. Platform is constructed of rectangular tubing and is decked with a reduced slip grating. Platform is adjustable in height from 2 ft. to 14 ft. from ground level, and includes a sliding access door. Deployment, raising, lowering, and pining of platform shall be done hydraulically. Platform will also include manual telescoping aluminum ladder, of which, the final design will be approved by customer prior to fabrication.

3.3   POWER PLANT & TRANSMISSION:

3.3.1

ENGINE

(1) Tier Ill Certified Caterpillar C-15, inline 6 cylinder, 4-stroke turbo charged, after-cooled engine rated at 475 hp. at 2,100 rpm. Engine includes a Donaldson dry-type air cleaner; and a spark arresting muffler exhaust system. Exhaust system discharges to right side of rig. Engine also comes with emergency shutdown system.

Engine includes a heavy-duty radiator and fan, engine speed governor, air-actuated throttle, standard engine instruments with hour meter, emergency shutdown for low oil and high coolant temperature, and an emergency shutdown button.

3.3.2

SPECIFICATlONS:

Model Number	C-15
Number of Cylinders	6
Engine Type	4-stroke / cycle
Displacement	15 Liters
Rated Power Output (Gross)	475 hp. @ 2,100 rpm

3.3.3

TRANSMISSION

(1) Allison M5610A automatic transmission provides 6 forward speeds and 1 reverse. Remote shifting is provided from the operators console via an electronic shifting system. Transmission uses separate cooler, integrated into the radiator.

All engine / transmission combinations are reviewed and approved by the transmission manufacturer for correct engineering, installation and engine compatibility. Taylor's exclusive design allows for the removal of engine, transmission, or transfer case independently.

SPECIFICATIONS:
Net Input Power (max.)		550 hp. (485 kW)
Net Input Speed (max.)		2,500 rpm
Net Input Torque (max.)		1,750 Ib.-ft. (2,373 N-m)
Torque Converter		Single stage, 3-element
Gear Ratios:
	First	4.00:1
	Second	2.68:1
	Third	2.01:1
	Fourth	1.35:1
	Fifth	1.00:1
	Sixth	0.67:1
	Reverse	-5.15:1

8

3.3.5

TRANSFER CASE

Commercially produced gear driven transfer case. 1-in / 2-out configuration, rated at 12,000 ft Ibs of torque. Transfer case distributes power to drawworks and carrier. Includes air activated disconnects for selection of road / winch gear.

3.4   AIR, ELECTRIC AND HYDRAULIC SYSTEMS:

3.4.1

AIR SYSTEM

(1) Engine driven 27.5-cfm compressor pressurizing a 5-tank air system plumbed in accordance with applicable DOT regulations and requirements. Check valves prevent accidental air pressure loss from system due to single line failure. Main air lines are plumbed with OEM style steel airlines and compression fittings rather than threaded pipe.

3.4.2

ELECTRICAL SYSTEM

12-volt electrical system, consisting of (1) 100 amp alternator, (3) BCI-31 batteries, (1) 12V starter and voltmeter. Batteries are located in a steel battery box mounted on the carrier deck. Location of box provides excellent access for maintenance and service.

3.4.3

HYDRAULIC SYSTEM

50 Gallon per minute system provides 2,000 psi. working pressure for all rig hydraulics and accessory drives. The pump is mounted in front of the rig engine and is directly coupled to the engine crankshaft, this is an exclusive Taylor feature. System features a bypass to tank while not in use. Hydraulic system incorporates a 200-gallon hydraulic tank with element style filters, suction strainer, and main tank shutoff.

3.4.4

TONG CIRCUIT

Rig hydraulic system provides a 2000 PSI / 50 GPM tong circuit. The system includes connectors, pressure & return lines, pressure gauge, and pressure regulator valve. Tongs, quick-connects, and tong hoses are not included as standard equipment.

3.5   TAYLOR 5-AXLE CARRIER:

3.5.1

OVERALL

The carrier is a heavy-duty 5-axle oilfield carrier with two front steering axles, two rear-driving axles, and one tag axle. All frame members coped and welded for superior strength and durability. The carrier is designed for maximum maneuverability, road clearance and turning radius. Location of axles specially engineered to correctly distribute weight in proportion to front and rear axles.

3.5.2

SPECIFICATI0NS*:

A: Length w/ Mast:	61 ft 9 in
B: Overhang (front)	14 ft. 9 in.
C: Axle to Front Bumper	5 ft.
D: Bridge Span	16 ft. 2 in.
E: Rear Axle Spacing	53 in.
F: Rear Axle to Back of Rig	11 ft. 8 in.
G: Height (over the road)	14 ft 3 in.

9

Width (traveling—not shown)		8 ft. 6 in.
Overhang (rear—not shown)		N/A
Max Ingress Angle		34 deg.
Max Egress Angle		17 deg.
Estimated Rig Weight
	Front:	28,760 Lbs.
	Rear:	51,260 Lbs.
	Total:	80,020 Lbs.

*Weight in standard configuration without block or line. Other specifications subject to change as engineering dictates.

3.5.3

CARRIER FRAME

21 in. wide-flange alloy H-beam, hand welded for strength. Coped cross members for increased strength and durability. Front and rear tow lugs are welded to the end of the frame rails for proper load distribution during towing. Frame is decked in 3/16 in. diamond tread decking with a 3-1/2 in. lip for strength and reduced flex.

3.5.4

FRONT AXLES

Steer able front tandem axle set is rated at 20,000 Ibs. per axle and Reyco front spring suspension rated at 22,000 Ibs per axle.

3.5.5

REAR DRIVING AXLES

Eaton 463 Series rear driving axles rated at 46,000 Ibs. Hendrickson walking beam rear suspension. Standard ratio is 6.17:1

3.5.6

REAR TAG AXLE

Non-driving rear axle with air suspension. Axle is rated for 20,000 Ib. capacity. Control for axle to be located near rear axles on operator's side.

3.5.7

BRAKE SYSTEM

DOT approved regulation antilock air brake system. Drum style brakes on all axles. Carrier is equipped with additional air emergency brake.

3.5.8

TIRES & WHEELS

The (4) four front tires are 445/65 R22.5 wide-base tires mounted on 13 in. x 22.5 in. steel hub-piloted "bud" type wheel. The (12) twelve rear tires are 11 R x 22.5 off-road tires mounted on 8 in. x 22.5 in. hub-piloted steel "bud" style wheels.

3.5.9

CAB

Single person cab set up for left-hand drive. Cab is equipped with air suspension seat, heater, defroster, windshield wiper, air horn, West Coast mirrors, and full instrumentation.

Instrumentation consists of speedometer, oil pressure, transmission oil temperature, water temperature, voltmeter, fuel meter, and front & rear air pressure gauges.

3.5.10

STEERING

Rig steering is a hydraulic assisted system, with (1) cylinder mounted on each axle and a hydraulic assisted steering box.

10

3.5.11

RIG LEVELING SYSTEM

Rig leveling is done with (4) hydraulic leveling jacks with locks. Jacks have 12 in. travel. The jacks are controlled from the operator's console. A leveling gauge is provided to assure quick easy rig leveling.

3.5.12

OTHER EQUIPMENT

The Taylor 5-axle carrier comes complete with integrated rig stairs, operator side fold-down walk ways with aluminum ladder, OSHA approved guardrails, driveline covers, junk rack, two (2) locking toolboxes, two (2) 125-gallon fuel tank, two (2) rear sill racks. Operators console will include (1) BOP control for blind rams and (1) BOP control for pipes.

3.6   PAINT & PREPARATION:

3.6.1

Preparation

Rig is thoroughly washed, sandblasted, and chemical etched prior to painting.

3.6.2

Primer Coat

Taylor Rig uses a zinc primer system. The primer is applied to a thickness of 3-—4 mills, exceeding industry standards. **note: no zinc coat

3.6.3

Finish Coat

The unit is finish coated in accordance with customer paint scheme. The finish coat is a polyurethane system for long lasting gloss and minimal chipping or pealing. Finish coat is 3-—4 mills in thickness, depending on color. Unless otherwise stated, engine will be painted to match the rig.

11

SECTION 4—ACCESSORIES & TOOLS

Taylor to provide the following general options at no additional cost.

•

Mount for oil saver pump



•

Jack Stands



•

Lubricator Rack—Slide Out



•

Tubing Tong Rack



•

Rod Tong Rack



•

Safety Chains on Tubing Board Fingers



•

Provisions for customer supplied Geronimo line from tubing and rod basket



•

Install customer supplied tong lift cylinder.



•

Board racks for front jack stands to the front side of the jack socket. Place rack at an angle 14" x 24" x 3" so board will not come out during transport.



•

Removable guard for back of tubing drum.



•

Derrick base mounted weight indicator bracket with 2" female hammer union connection. Hammer union mounted in place that gives operator good line of view from operator's platform.



•

Hooks on rear jack sockets for weight indicator pads.



•

Kill switch to sand drum control panel.



•

T between fuel tanks with valve and safety plug.

12

SECTION 5—RIG OPTIONS

5.1    Tool Tub In Derrick Base	$425.00
Add Tool Tub in derrick base in a manner not to prohibit the removal or replacement of the tubing tongs. The tub should run the width of the base and be approx 18" deep x 12" tall. Tub should have reinforcements and nubs to store slips, 2/38" tubing elevators, 2/78" tubing elevators and keepers for Hyd. Rod tongs. Tub will have 314" hooks on each corner.
5.2    BOP Controls	$934.00
Add (2) Air over hydraulic BOP controls to operators console. (1) For blind & (1) For Pipe Rams. Includes all plumbing and mounting of controls in console.
5.3    Winch Control	$1,231.00
Add (1) Air over hydraulic Winch Control to operators console. Includes all plumbing and mounting of control in console.
5.4    Hydraulic Pressure Gauge	$284.00
Add Main Hydraulic Pressure gauge to Console.
5.5    Delete Tool Box	($550.00)
Delete tool box after staircase towards the rear of the rig on operator side and replace with junk rack.
5.6    Custom Deck Mounted Stand Up Tool Box	$1,510.00
Add a custom deck mounted stand up tool box on off-operator side from end of drawworks towards rear of rig. Approx. dimensions of tool box are 40" H x 36" W x 16" D. The box should be equipped with hooks inside for 36" & 24" pipe wrenches and other smaller hand tools. Please note: That the junk rack will be extended to take place of the deleted tool box.
5.7    Hydraulic Walkways	$7,581.00
Add hydraulic walkways.
5.8    Main Drum Disc Guard	$612.00
Add protective guards to main drum discs.
5.9    Winch Guard Cover	$186.00
Add winch guard cover.

13

SECTION 6—RIG SPARES

None Contracted

14

SECTION 7—DELIVERY & COMMISSIONING

7.1

PRE-DELIVERY INSPECTION

Taylor will conduct a standard pre-delivery systems test. These tests check function and operation of rig and associated components. Customer is provided copy of inspection report. Unless otherwise listed in this contract, the unit will at no time be tested with destructive testing methods such as load, dynamometer, or other tests.

7.2

PACKAGING

No packaging is included in this contract.

7.3

RIG SHIPPING

Each unit is priced FOB, customer's yard, so long as yard is inside the contiguous United States. Delivery to Alaska or Hawaii is not included. In those cases, delivery is to the Port of Houston.

7.4

TRAINING

Taylor provides a 6-hour training and orientation program for up to 6 persons. This training is provided at the customer's yard during normal business hours. After hours or weekend training is available at an additional charge.

NOTE:    Customer is required to attend a 6 hour training program performed by a Taylor representative. This training may take place at Taylor facility or during rig commissioning at customer's location. Customer's failure to attend this training renders all warranties void.

7.5

ON-SITE COMMISSIONING

1-day on-site commissioning during normal business hours is provided in this contract. After hours or weekend commissioning is available at an additional charge.

7.6

DELIVERY SCHEDULE

Please refer to Appendix A for all scheduled delivery dates.

A late delivery penalty will be paid by Taylor in the event of a delay, as outlined in the "Terms and Conditions" section of this contract.

15

SECTION 8—DOCUMENTATION

8.1

CONTRACT

Customer will be provided (1) original copy of the purchase contract, and up to 5 additional copies of the contract as needed.

8.2

INVOICES

Taylor will present the customer with invoices for all moneys due. Invoices will indicate contract amount and all payment due information.

8.3

MANUFACTURERS STATEMENT OF ORIGIN

Taylor will provide a Manufacturers Statement of Origin (MSO) for the unit. This document proves the legal ownership of the unit. MSO will indicate the Vehicle Identification Number (VIN) as well as all applicable component serial numbers. This document will be executed and transferred after final payment for unit is received.

8.4

OWNERS MANUAL

The unit will be accompanied by an owner's manual to assist in the operation and service of the unit. Due to the custom nature of each unit, the manual will be provided within 2 weeks of rig completion.

16

SECTION 9—WARRANTY

Taylor Rigs warrants that the rig shall be free from defects in material and workmanship for a period of one (1) year from date of service. Additionally, Taylor warrants that all drawworks parts, except for brake pads and expendables will be warranted for a period of two (2) years from date of service. A three (3) year warranty will be provided on the paint system. The paint warranty covers pealing or paint adhesion issues. Provided, however, in no event does Taylor Rigs warrant the engine, drive train components, or third party components of the Rig, but Taylor Rigs shall, to the extent possible, transfer to Customer any original equipment manufacturer warranty on such components.

If any defects covered by this Warranty appear within the warranty period, Taylor Rigs shall have the option of repairing or replacing the defective equipment at its expense.

Taylor will provide the customer with a proprietary 24 hr. warranty "hot line" number.

Taylor warrants having any warranty part available for same day shipment at any time during the warranty period. If Taylor does not have the part available, then the part is supplied at no cost to the customer.

Taylor warranties to have a service person on site, upon Customer's request, with in 6 hours from the time of notice. This person does not have to be a Taylor Rig employee, but an authorized representative of Taylor. Additionally, at the Customer's request, Taylor will have a Taylor Rig employee dispatched to the rig site with in one hour of request.

This Warranty does not extend to any equipment which has (a) been subjected to misuse, neglect, accident or abuse or casualty loss; (b) repaired or altered by anyone other than Taylor Rigs without its express written prior approval; (c) improperly installed by someone other than Taylor Rigs; or (d) used in violation of instructions furnished by Taylor Rigs.

THE ABOVE WARRANTY SHALL BE IN LIEU OF ALL OTHER WARRANTIES AND ALL OTHER WARRANTIES, EXPRESS OR IMPLIED, INCLUDING BUT NOT LIMITED TO, IMPLIED WARRANTIES OF MERCHANTABILITY AND FITNESS FOR A PARTICULAR PURPOSE ARE DISCLAIMED.

TAYLOR RIGS' LIABILITY WHETHER IN CONTRACT, IN TORT, UNDER WARRANTY, IN NEGLIGENCE OR OTHERWISE, SHALL, TO EXTENT PERMITTED BY LAW, BE LIMITED TO THE REPAIR OR REPLACEMENT OF ANY DEFECTIVE PARTS. IN NO EVENT SHALL TAYLOR RIGS BE LIABLE FOR SPECIAL OR CONSEQUENTIAL DAMAGES, OR DAMAGES FOR LOSS OF BUSINESS PROFITS, BUSINESS INTERRUPTION, OR ANY OTHER PECUNIARY LOSS ARISING OUT OF THE USE OR INABILITY TO US THE RIG (INCLUDING THE INABILITY TO USE THE RIG BY REASON OF DELAY).

TRAINING:    Customer is required to attend a 6 hour training program performed by a Taylor representative. This training may take place at Taylor facility or during rig commissioning at customer's location. Customer's failure to attend this training renders all warranties void.

17

SECTION 10—PRICING

	PRICE EACH		TOTAL FOR 24
BASE RIG	$	625,126.00	$	15,003,024.00
RIG OPTIONS	$	12,213.00	$	293,112.00
TOTAL PROJECT PRICE, 24 UNITS FOB CUSTOMER'S YARD, US FUNDS			$	15,296,136.00

*All prices contracted herein are subject to terms and conditions of Taylor Rigs, LLC, included in Section 11 of this contract. Unless otherwise stated, contracted prices do not include export packaging, rig-up, or other similar fees.

18

SECTION 11—STANDARD TERMS & CONDITIONS

The contract on the attached pages is subject to the following terms and conditions:

•

Terms of Payment. Unless otherwise stated herein, all payments must be made in a timely manner according to the following payment schedule and milestones: See Appendix A to contract CP-05-023. Not withstanding milestones outlined in Appendix A, in the event of a failure to make any payment, Taylor Rigs shall have the right to cease any manufacturing with respect to this order and delay shipment accordingly. If Customer fails to make any final installment(s) of the Total Price within 30 days of the payment date, Taylor may treat the Contract as wrongfully canceled, and the customer will be subject to terms and penalties listed below. Additionally, Taylor agrees to allow the customer to delay progress payments if other rigs in process have not met scheduled milestone completions according to the provided time line.



•

Delivery or Completion. Taylor Rigs shall not be liable for any damage or penalty for delays in delivery or completion due to acts of God, acts or omissions of the Customer, acts of civil or military authorities, governmental regulation or priorities, fires, floods, epidemics, war, riots, strikes, third party material or manufacturing delays, transportation delays, impossibility or impracticability of performance or any other cause or causes beyond the control of Taylor Rigs, whether similar to the foregoing or otherwise. In the event of a delay caused by the aforesaid, the delivery and/or completion date shall be extended for a period equal to any such delay, and this Contract shall not be void or voidable as a result thereof.

Taylor guarantees delivery, subject to restrictions above. The guarantee provides a penalty equal to 1% of the individual units total contract price for each week after the guaranteed delivery date, up to a maximum of 5%. If in the event of a delay of more than 5 weeks, then Customer has the option to cancel the purchase of that particular unit.

Taylor rigs agrees to allow 4 of the 24 rigs contracted herein to become C700 series rigs at the price of $781,793.00 each per contract CP-05-005. Delivery of the C700 rigs shall begin no sooner than the end of the first quarter of 2006. Notification by Basic to Taylor would need to be received no later than October 1^st 2005 in order to meet the March 2006 delivery date.

•

Cancellation. This Contract is not subject to cancellation without the express written consent of Taylor Rigs except as a result of default by Taylor Rigs, in which event, customer may terminate this Contract without penalty. In the event Taylor Rigs allows cancellation by the customer, the deposit would be refunded up to the difference between contracted agreed sale price by the customer and Taylor Rigs, and the actual price received from sale of equipment to another customer. In addition, there shall be a mandatory cancellation fee set forth as follows: Beginning from date of contract signing up to 15 days in the amount of 5%; 15-30 days 15% and anytime thereafter to date of delivery 25%. Cancellation penalty is effective for any rigs in which deposits are due and/or have been placed. Nothing herein shall be deemed to impose an obligation on Taylor Rigs to agree to any cancellation on any terms. In the event of a cancellation or other breach of this Contract by Customer, in addition to retaining above listed funds, Taylor Rigs may be entitled to seek such other remedies as it may have at law or in equity.



•

Jurisdiction. The parties hereto irrevocably and unconditionally consent to and submit themselves to the exclusive jurisdiction of the courts of the State of Oklahoma located in Tulsa County, Oklahoma and the courts of the United States of America located in the Northern District of Oklahoma (collectively, the "Agreed Courts") with respect to any actions, suits or proceedings arising out of or in connection with this Contract and the transactions contemplated hereby and the parties hereto agree not to commence any action, suit or proceeding relating thereto except in such Agreed Courts. The parties hereto irrevocably and unconditionally waive any objection to the laying of venue of any action, suit or proceeding arising out of this Contract or the transactions contemplated hereby in the Agreed Courts and hereby further irrevocably and unconditionally waive and agree not to plead or claim that any such action, suit or proceeding brought in any of the Agreed Courts has been brought in an inconvenient forum.

19

SECTION 12—PARTS SALE AGREEMENT

Taylor agrees so long as this contract is legally fulfilled by the Customer and not subject to any cancellation, Taylor will resell any part or component, for these units, at a 10% mark-up from cost. This is a 10% mark-up from Taylor Rigs purchase price including shipping to Taylor's Tulsa, Ok facility. Shipping from Tulsa is not included in this portion of the contract.

20

SECTION 13—CONTRACT ACCEPTANCE

CUSTOMER, HAVING CAREFULLY READ PAGES 1-22 (ALL PROVISIONS) OF THIS CONTRACT, ACKNOWLEDGES RECEIPT OF A COPY OF THIS CONTRACT WHICH IS THE FINAL EXPRESSION OF THE AGREEMENT OF THE PARTIES, AND THE COMPLETE AND EXCLUSIVE STATEMENT OF THE TERMS AND CONDITIONS AGREED UPON, ALL PRIOR AGREEMENTS AND UNDERSTANDINGS BEING MERGED HEREIN, AND THAT THERE ARE NO REPRESENTATIONS, WARRANTIES OR STIPULATIONS, EITHER ORAL OR WRITTEN NOT HEREIN CONTAINED. NO MODIFICATIONS OF THIS AGREEMENT MAY BE MADE EXCEPT BY WRITTEN AGREEMENT EXECUTED BY BOTH CUSTOMER AND TAYLOR RIGS. THIS AGREEMENT SHALL NOT BE BINDING UPON TAYLOR RIGS UNTIL ACCEPTED BY AN AUTHORIZED OFFICER OF TAYLOR RIGS.

ALL PRICES, SPECIFICATIONS, AND CONDITIONS ARE SATISFACTORY AND ARE HEREBY ACCEPTED, SUBJECT TO THE TERMS SET FORTH ABOVE AND THOSE GENERAL TERMS AND CONDITIONS OF THE CONTRACT INCLUDED HEREIN. TAYLOR RIGS, LLC IS AUTHORIZED TO PERFORM THE WORK AS SPECIFIED, PAYMENT WILL BE MADE AS OUTLINED ABOVE.

Company:	Basic Energy Services	Taylor Rigs, LLC
Accepted By:	/s/ K.V. Huseman	Accepted By:	/s/ Brett Taylor
Date:	5/19/05	Date:	5/19/05

21

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Exhibit 10.17

(Taylor Logo)
TABLE OF CONTENTS

EX-10.19

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Exhibit 10.19

Form of Share Tender and Repurchase Agreement

        This Share Tender and Repurchase Agreement ("Agreement") is being executed by and between Basic Energy Services, Inc., a Delaware corporation (the "Company"), and the undersigned holder (the "Holder"). The Holder hereby agrees to tender, and hereby irrevocably tenders, to the Company:

        (A)                        shares of common stock of the Company (the "Common Stock") (including shares of Common Stock issued as a stock dividend paid on September 26, 2005, the "2005 Tendered Shares") to cover the estimated tax obligations (the "2005 Tax Obligations") set forth in Schedule I of the "Stock-Related Tax Payment Plan" letter dated October 21, 2005 from the Company to the Holder. The number of 2005 Tendered Shares shall not exceed 39.2% of the vested shares (rounding up to the nearest whole share) owned by the Holder and issued to the Holder as compensation for employment, and with respect to the 2005 Tax Obligations includes shares issued upon the exercise of warrants; and

        (B)                        shares of Common Stock (together with any shares of Common Stock issued as a stock dividend or in connection with a stock split thereon, the "2006 Tendered Shares") to be held by the Company for tender to cover estimated tax obligations (the "2006 Tax Obligations") for restricted shares owned by the Holder vesting as of February 24, 2006 (the "2006 Vesting Date"). The number of 2006 Tendered Shares shall not exceed 36.45% of the currently restricted shares (rounding up to the nearest whole share) owned by the Holder and vesting as of the 2006 Vesting Date.

        2005 Tendered Shares and 2005 Tax Obligations.    The Company and the Holder agree that the price to be tendered or paid per share of the 2005 Tendered Shares shall be a price equal to the initial price to public, less underwriting discounts and commissions, received by the Company in connection with its public offering of shares of Common Stock (the "IPO") pursuant to the registration statement on Form S-1 filed with the U.S. Securities and Exchange Commission (File No. 333-127517). The Company shall pay the amount of the withholding tax liability on the 2005 Tax Obligations satisfied by the tender of the 2005 Tendered Shares to the Internal Revenue Service. The Company shall pay the remaining amounts paid for the 2005 Tendered Shares to the Holder by check or wire transfer. The Holder acknowledges that the Holder is required to pay any remaining tax liability of the Holder in cash.

        2006 Tendered Shares and 2006 Tax Obligations.    The Company and the Holder agree that the price to be tendered or paid per share of the 2006 Tendered Shares shall be the price equal to the closing price per share of Common Stock the 2006 Vesting Date. The Company shall pay the amount of the withholding tax liability for any 2006 Tax Obligations satisfied by the tender of the 2006 Tendered Shares to the Internal Revenue Service. The Company shall pay the remaining amounts paid for the 2006 Tendered Shares to the Holder by check or wire transfer. The Holder acknowledges that the Holder is required to pay any remaining tax liability of the Holder in cash.

        Investment Decision.    The Holder agrees that Holder has made his own investment decision and has not relied on the Company or any of its officers, directors, employees or other representatives for investment advice in connection with the tender and sale of the shares of Common Stock. The Holder agrees that he in knowledgeable regarding the business and affairs of the Company, and has had the opportunity to ask questions and to obtain information from the Company regarding his decision to tender and sell the shares of Common Stock.

        No Liens.    The Holder hereby represents, warrants and covenants to the Company that the Holder has, and until the 2006 Vesting Date will have, good and valid title to the 2005 Tendered Shares and 2006 Tendered Shares, free and clear of any liens, pledges, other claims or encumbrances other than (i) encumbrances under the Company's Second Amended and Restated Stockholders' Agreement dated as of April 2, 2004 and (ii) encumbrances set forth in the applicable restricted stock grant agreement with the Company; and upon delivery of such shares and payment of consideration pursuant

to this Agreement, good and valid title to such shares, free and clear of all liens, pledges, other claims or encumbrances will pass to the Company.

        Certificates for Shares.    The Holder hereby directs the Company, and the Company hereby agrees, to return to the Holder a stock certificate representing the difference, if any, in (i) the number of shares represented by the stock certificate(s) delivered to the Company by the Holder (together with any stock certificates issued on such shares as part of a stock split or stock dividend) and (ii) the number of 2005 Tendered Shares and 2006 Tendered Shares in this Share Tender Agreement. The Company shall retain and hold as security for the performance of this Agreement a certificate representing the number of 2006 Tendered Shares.

        Additional Agreements.    The Holder agrees to execute any other instruments or documents as reasonably needed by the Company to effect the transfer and assignment of the shares of Common Stock tendered in accordance with this Agreement.

        Termination.    This Agreement shall terminate and be of no further effect in the event that the closing of the IPO does not occur prior to December 31, 2005. In such event, the Company shall return the certificates for the shares tendered by the Holder.

        Governing Law.    This Agreement shall be governed by, and construed in accordance with, the laws of the State of Texas, without giving effect to choice of law rules.

        Waiver of Jury Trial.    Each of the parties hereto hereby waives, to the fullest extent permitted by applicable law, any right it may have to a trial by jury in any legal proceeding directly or indirectly arising out of or relating to this Agreement. Each party hereto acknowledges to the other that it has been induced to enter into this Agreement by, among other things, this mutual waiver.

        IN WITNESS WHEREOF, the Holder has executed this Agreement as of this          day of                                    , 2005.

Printed Name:                                                                                           

Accepted and Agreed as of                                         , 2005:

Basic Energy Services, Inc.

By:

Name:

Title:

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Exhibit 10.19

Form of Share Tender and Repurchase Agreement

EX-21.1

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Exhibit 21.1

Subsidiaries of Basic Energy Services, Inc.

Name of Subsidiary	Jurisdiction of Formation	Effective Ownership
Basic Energy Services GP, LLC	Delaware	Basic Energy Services, Inc.—100%
Basic Energy Services LP, LLC	Delaware	Basic Energy Services, Inc.—100%
Basic Energy Services L.P.	Delaware	Basic Energy Services GP, LLC—0.01% Basic Energy Services LP, LLC—99.99%
Basic ESA, Inc.	Texas	Basic Energy Services L.P.—100%
Energy Air Drilling Services Co., Inc.	Colorado	Basic Energy Services L.P.—100%
R & R Hot Oil Service Inc.	North Dakota	Basic Energy Services L.P.—100%
Basic Marine Services, Inc.	Delaware	Basic Energy Services L.P.—100%
First Energy Services Company	Delaware	Basic Energy Services L.P.—100%
Western Oil Well Service Co.	Montana	First Energy Services Company—100%
FESCO Alaska, Inc.	Alaska	First Energy Services Company—100%
H.B.&R., Inc.	Montana	FESCO Alaska—100%

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Exhibit 21.1

EX-23.1

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Exhibit 23.1

Consent of Independent Registered Public Accounting Firm

The Board of Directors
Basic Energy Services, Inc.:

        We consent to the use of our report dated June 13, 2005, except as to Note 19b, which is as of July 25, 2005, Note 19c, which is as of September 22, 2005 and Note 20, which is as of October 31, 2005, with respect to the consolidated balance sheets of Basic Energy Services, Inc. as of December 31, 2004 and 2003, 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, 2004, included herein and to the reference to our firm under the heading "Experts" in the registration statement and related prospectus. Our report refers to a change in accounting for asset retirement obligations as of January 1, 2003 and to a change in accounting for goodwill and other intangible assets as of January 1, 2002. Our report also refers to a restatement of the consolidated statements of operations, stockholders' equity, and cash flows for each of the years in the two-year period ended December 31, 2003.

        We also consent to the use of our report dated August 3, 2005, with respect to the combined statements of operations, equity and cash flows of PWI, Inc., PWI Management, LLC, Parker Windham, Ltd., PWI Rentals, L.P., PWI Express Services, L.P. and PWI Disposal, L.P. (collectively referred to as "PWI") for the nine months ended September 30, 2003, included herein and to the reference to our firm under the heading "Experts" in the registration statement and related prospectus. Our report refers to a change in accounting for asset retirement obligations as of January 1, 2003.

KPMG LLP
Dallas, Texas

November 4, 2005

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Exhibit 23.1

Consent of Independent Registered Public Accounting Firm

EX-23.2

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Exhibit 23.2

CONSENT OF INDEPENDENT ACCOUNTANTS

        We hereby consent to the use in this Amendment No. 2 to the Registration Statement on Form S-1 of our report dated March 7, 2003, except with respect to the matter discussed in Note 11, for which the date is August 28, 2003, relating to the financial statements of FESCO Holdings, Inc. and Subsidiaries, which appears in such Registration Statement. We also consent to the reference to us under the heading "Experts" in such Registration Statement.

/s/ PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
Denver, Colorado
November 3, 2005

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Exhibit 23.2

CONSENT OF INDEPENDENT ACCOUNTANTS

CORRESP