exv99w3

Exhibit 99.3

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATION

Management’s Overview

We provide a wide range of well site services to oil and gas drilling and producing companies, including well servicing, fluid services, completion and remedial services and contract drilling services. Our results of operations reflect the impact of our acquisition strategy as a leading consolidator in the domestic land-based well services industry. Our acquisitions have increased our breadth of service offerings at the well site and expanded our market presence. In implementing this strategy, we have purchased businesses and assets in 43 separate acquisitions from January 1, 2003 to December 31, 2007. Our weighted average number of well servicing rigs has increased from 126 in 2001 to 386 in the fourth quarter of 2007, and our weighted average number of fluid service trucks has increased from 156 to 656 in the same period. In 2007, we significantly increased our completion and remedial services segment, principally through the acquisition of JetStar Consolidated Holdings, Inc. Our weighted average number drilling rigs has increased from two in the first quarter of 2006 to 10 in the fourth quarter of 2007, principally through the acquisition of Sledge Drilling Holding Corp. These acquisitions make changes in revenues, expenses and income not directly comparable between periods.

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

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


	Year Ended December 31,
	2007				2006				2005
Revenues:
Well servicing	$	342.7	39	%	$	323.7	44	%	$	222.0	48	%
Fluid services		259.3	29	%		245.0	34	%		178.0	39	%
Completion and remedial services		240.7	28	%		154.4	21	%		59.8	13	%
Contract drilling		34.5	4	%		7.0	1	%		—	0	%

Total revenues	$	877.2	100	%	$	730.1	100	%	$	459.8	100	%

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

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

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

increased drilling activity by our customers. In 2007, natural gas prices declined as an excess supply of natural gas began to occur, mainly due to moderate U.S. weather patterns. Utilization for our services declined from 2006 levels as drilling activity flattened or declined in several of our markets and new equipment entered the marketplace balancing supply and demand for our services. However, pricing for our services improved in 2007 from 2006, mainly reflecting continued increases in labor costs, and offset a portion the effect of the lower utilization of our services on our total revenues. In 2008, we expect that the utilization of our services and pricing for these services will be comparable to 2007 assuming oil and gas prices and U.S. drilling activity remain at or near current levels.

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

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

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

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

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

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

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

Recent Strategic Acquisitions and Expansions

During the period from 2005 through 2007, we grew significantly through acquisitions and capital expenditures. During 2005, we directed our focus for growth primarily on the integration and expansion of our existing businesses through capital expenditures and to a lesser extent, acquisitions. During 2006, we completed ten acquisitions, of which G&L Tool, Ltd. was considered significant for purposes of Statement of Financial Accounting Standards No. 141 (SFAS No. 141) ”Business Combinations.” During 2007, we completed eight acquisitions, of which JetStar Consolidated Holdings, Inc. and Sledge Drilling Holding Corp. were considered significant for purposes of SFAS No. 141.

We discuss the aggregate purchase prices and related financing issues below in “— Liquidity and Capital Resources” and present the pro forma effects of the acquisition of G&L Tool, Ltd., JetStar Consolidated Holdings, Inc., and Sledge Drilling Holding Corp. in note 3 of our historical consolidated financial statements included in this report.

Selected 2005 Acquisitions

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

MD Well Service, Inc.

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

Oilwell Fracturing Services, Inc.

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

Selected 2006 Acquisitions

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

LeBus Oil Field Service Co.

On January 31, 2006, we acquired all of the outstanding capital stock of LeBus Oil Field Service Co. for an acquisition price of $26 million, subject to adjustments. This acquisition significantly expanded our fluid services segment in the Ark-La-Tex region. The cash used to acquire LeBus was primarily from borrowings under our senior credit facility.

G&L Tool, Ltd.

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

Chaparral Service, Inc.

On August 15, 2006, we acquired all of the outstanding capital stock and substantially all operating assets of the subsidiaries of Chaparral Service, Inc. for total consideration of $19 million cash, subject to adjustments. This acquisition expanded our well servicing and fluid services capabilities in the eastern New Mexico portion of the Permian Basin. The cash used to acquire Chaparral was primarily from operating cash.

Selected 2007 Acquisitions

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

Parker Drilling Offshore USA, LLC

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

JetStar Consolidated Holdings, Inc.

On March 6, 2007, we acquired all of the outstanding capital stock of JetStar Consolidated Holdings, Inc. (“JetStar”) for an aggregate purchase price of approximately $127.3 million, including $86.3 million in cash, of which approximately $37.6 million was used for the retirement of JetStar’s outstanding debt. As part of the purchase

price, we issued 1,794,759 shares of common stock, at a fair value of $22.86 per share for a total fair value of approximately $41 million. This acquisition operates in our completion and remedial business segment.

Sledge Drilling Holding Corp.

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

Wildhorse Services, Inc.

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

Segment Overview

Well Servicing

In 2007, our well servicing segment represented 39% of our revenues. Revenue in our well servicing segment is derived from maintenance, workover, completion and plugging and abandonment services. We provide maintenance-related services as part of the normal, periodic upkeep of producing oil and gas wells. Maintenance-related services represent a relatively consistent component of our business. Workover and completion services generate more revenue per hour than maintenance work due to the use of auxiliary equipment, but demand for workover and completion services fluctuates more with the overall activity level in the industry.

We typically charge our well servicing rig customers for services on an hourly basis at rates that are determined by the type of service and equipment required, market conditions in the region in which the rig operates, the ancillary equipment provided on the rig and the necessary personnel. We measure the activity level of our well servicing rigs on a weekly basis by calculating a rig utilization rate which is based on a 55-hour work week per rig.

Our well servicing rig fleet has increased from a weighted average number of 291 rigs in the first quarter of 2005 to 386 in the fourth quarter of 2007 through a combination of newbuild purchases and the remainder through acquisitions and other individual equipment purchases.

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


	Weighted
	Average				Rig					Profits
	Number of		Rig		Utilization			Revenue Per		Per Rig		Segment
	Rigs		Hours		Rate			Rig Hour		Hour		Profits%
2005:
First Quarter		291		175,300		84.3	%	$	255	$	94		37.1	%
Second Quarter		303		192,400		88.8	%	$	280	$	107		38.2	%
Third Quarter		311		198,000		89.0	%	$	299	$	108		36.0	%
Fourth Quarter		316		195,000		86.3	%	$	329	$	134		40.7	%
Full Year		305		760,700		87.1	%	$	292	$	111		38.1	%
2006:
First Quarter		325		208,700		89.8	%	$	349	$	157		44.9	%
Second Quarter		337		219,300		91.0	%	$	365	$	165		45.2	%
Third Quarter		351		226,300		90.2	%	$	379	$	175		46.1	%
Fourth Quarter		360		213,900		83.1	%	$	398	$	174		43.8	%
Full Year		344		868,200		88.2	%	$	373	$	168		45.0	%
2007:
First Quarter		364		210,800		81.0	%	$	411	$	174		42.2	%
Second Quarter		371		207,700		78.3	%	$	415	$	163		39.5	%
Third Quarter		383		212,100		77.7	%	$	414	$	166		40.0	%
Fourth Quarter		386		200,600		72.7	%	$	409	$	159		38.8	%
Full Year		376		831,200		77.3	%	$	412	$	166		40.1	%

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

Fluid Services

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

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


					Segment
	Weighted				Profits
	Average				Per
	Number of		Revenue Per		Fluid
	Fluid Service		Fluid Service		Service		Segment
	Trucks		Truck		Truck		Profits%
2005:
First Quarter		435	$	88	$	27		31.1	%
Second Quarter		447	$	95	$	34		35.4	%
Third Quarter		465	$	98	$	36		36.8	%
Fourth Quarter		472	$	109	$	42		38.1	%
Full Year		455	$	391	$	139		35.6	%
2006:
First Quarter		529	$	101	$	37		36.4	%
Second Quarter		568	$	109	$	42		38.2	%
Third Quarter		614	$	105	$	38		36.7	%
Fourth Quarter		640	$	103	$	39		38.0	%
Full Year		588	$	417	$	156		37.4	%
2007:
First Quarter		652	$	98	$	37		37.5	%
Second Quarter		657	$	96	$	35		36.1	%
Third Quarter		653	$	97	$	35		35.7	%
Fourth Quarter		656	$	104	$	37		35.7	%
Full Year		655	$	396	$	144		36.2	%

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

Completion and Remedial Services

In 2007, our completion and remedial services segment represented 28% of our revenues. Revenues from our completion and remedial services segment are generally derived from a variety of services designed to stimulate oil and gas production or place cement slurry within the wellbores. Our completion and remedial services segment includes pressure pumping, rental and fishing tool operations, cased-hole wireline services and underbalanced drilling.

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

We entered the rental and fishing tool business through our acquisition of G&L in the first quarter of 2006. This acquisition consisted of 16 rental and fishing tool stores in the North Texas, West Texas, and Oklahoma markets. We have since further expanded this business line with several acquisitions and have 18 rental and fishing tool stores as of December 31, 2007.

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

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

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


			Segment
	Revenues		Profits%
2005:
First Quarter	$	10,764		45.6	%
Second Quarter	$	13,512		49.1	%
Third Quarter	$	15,883		48.2	%
Fourth Quarter	$	19,673		49.5	%
Full Year	$	59,832		48.4	%
2006:
First Quarter	$	27,455		49.5	%
Second Quarter	$	40,939		53.1	%
Third Quarter	$	42,109		51.3	%
Fourth Quarter	$	43,909		51.2	%
Full Year	$	154,412		51.5	%
2007:
First Quarter	$	46,137		49.9	%
Second Quarter	$	63,735		47.6	%
Third Quarter	$	66,304		47.6	%
Fourth Quarter	$	64,515		46.2	%
Full Year	$	240,692		47.7	%

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

Contract Drilling

In 2007, our contract drilling segment represented 4% of our revenues. Revenues from our contract drilling segment are derived primarily from the drilling of new wells.

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

Our contract drilling rig fleet grew from four during the first quarter of 2007 to 10 by the fourth quarter, due to the Sledge Drilling acquisition.

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


	Weighted
	Average		Rig
	Number of		Operating		Revenue		Profits (Loss)			Segment
	Rigs		Days		Per Day		Per Day			Profits%
2006:
First Quarter		2		12		N.M.		N.M.			N.M.
Second Quarter		2		104	$	11,700	$	(4,900	)		-45.2	%
Third Quarter		2		160	$	14,700	$	1,600			10.9	%
Fourth Quarter		3		208	$	13,300	$	(1,600	)		-11.7	%
Full Year		2		484	$	14,400	$	(3,000	)		-20.5	%
2007:
First Quarter		3		168	$	11,500	$	(5,200	)		-44.9	%
Second Quarter		8		594	$	17,200	$	6,900			39.5	%
Third Quarter		9		723	$	15,700	$	6,700			42.4	%
Fourth Quarter		10		748	$	14,600	$	5,300			36.3	%
Full Year		8		2,233	$	15,400	$	5,400			34.7	%

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

Operating Cost Overview

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

Critical Accounting Policies and Estimates

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

Critical Accounting Policies

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

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

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

Self-Insured Risk Accruals. We are self-insured up to retention limits with regard to workers’ compensation and medical and dental coverage of our employees. We generally maintain no physical property damage coverage on our workover rig fleet, with the exception of certain of our 24-hour workover rigs and newly manufactured rigs. We have deductibles per occurrence for workers’ compensation and medical and dental coverage of $250,000 and $175,000 respectively. We have lower deductibles per occurrence for automobile liability and general liability. We maintain accruals in our consolidated balance sheets related to self-insurance retentions by using third-party actuarial data and historical claims history.

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

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

Critical Accounting Estimates

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

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

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

Impairment of Goodwill. Our goodwill is considered to have an indefinite useful economic life and is not amortized. We assess impairment of our goodwill annually as of December 31 or on an interim basis if events or circumstances indicate that the fair value of the asset has decreased below its carrying value.

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

Litigation and Self-Insured Risk Reserves. We estimate our reserves related to litigation and self-insure risk based on the facts and circumstances specific to the litigation and self-insured risk claims and our past experience with similar claims. The actual outcome of litigation and insured claims could differ significantly from estimated amounts. As discussed in “— Self-Insured Risk Accruals” above with respect to our critical accounting policies, we maintain accruals on our balance sheet to cover self-insured retentions. These accruals are based on certain

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

Fair Value of Assets Acquired and Liabilities Assumed. We estimate the fair value of assets acquired and liabilities assumed in business combinations, which involves the use of various assumptions. These estimates may be affected by such factors as changing market conditions, technological advances in industry or changes in regulations governing the industry. The most significant assumptions, and the ones requiring the most judgment, involve the estimated fair value of property and equipment, intangible assets and the resulting amount of goodwill, if any. We test annually for impairment of the goodwill and intangible assets with indefinite useful lives recorded in business combinations. This requires us to estimate the fair values of our own assets and liabilities at the reporting unit level. Therefore, considerable judgment, similar to that described above in connection with our estimation of the fair value of acquired company, is required to assess goodwill and certain intangible assets for impairment.

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

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

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

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

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

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

Results of Operations

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Liquidity and Capital Resources

Currently, our primary capital resources are net cash flows from our operations, utilization of capital leases as allowed under our 2007 Credit Facility and availability under our 2007 Credit Facility, of which approximately $59.5 million was available at December 31, 2007. As of December 31, 2007, we had cash and cash equivalents of $91.9 million compared to $51.4 million as of December 31, 2006. We have utilized, and expect to utilize in the future, bank and capital lease financing and sales of equity to obtain capital resources. When appropriate, we will consider public or private debt and equity offerings and non-recourse transactions to meet our liquidity needs.

Net Cash Provided by Operating Activities

Cash flow from operating activities was $198.6 million for the year ended December 31, 2007 as compared to $145.7 million in 2006, and $99.2 million in 2005. The increase in 2007 was due primarily to higher depreciation

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

Capital Expenditures

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

For 2008, we currently have planned approximately $115 million in cash capital expenditures and $33 million in new capital leases, none of which is planned for acquisitions. We do not budget acquisitions in the normal course of business, but we believe that we may spend a significant amount for acquisitions in 2008. The $115 million of cash capital expenditures planned for property and equipment is primarily for (1) purchase of additional equipment to expand our services, (2) continued refurbishment of our well servicing rigs and (3) replacement of existing equipment. We regularly engage in discussions related to potential acquisitions related to the well services industry.

Capital Resources and Financing

Our current primary capital resources are cash flow from our operations, the ability to enter into capital leases of up to an additional $87.5 million at December 31, 2007, the availability under our credit facility of $59.5 million at December 31, 2007 and a cash balance of $91.9 million at December 31, 2007. In 2007, we financed activities in excess of cash flow from operations primarily through the use of bank debt and capital leases.

We have significant contractual obligations in the future that will require capital resources. Our primary contractual obligations are (1) our long-term debt, (2) interest on long-term debt, (3) our capital leases, (4) our operating leases, (5) our rig purchase obligations, (6) our asset retirement obligations, and (7) our other long-term liabilities. The following table outlines our contractual obligations as of December 31, 2007 (in thousands):


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

Total	$	641,270	$	68,076	$	237,051	$	41,696	$	294,447

Our long-term debt, excluding capital leases, consists primarily of term loan and revolver indebtedness outstanding under our senior credit facilities. Interest on senior notes relates to our future contractual interest obligation on our $225 million 7.125% Senior Notes offering in April of 2006 and $150 million outstanding under our 2007 credit facility. Interest on our 2007 credit facility is payable based upon the amount outstanding at December 31, 2007, at an interest rate of LIBOR plus 125 basis points. Our capital leases relate primarily to light-duty and heavy-duty vehicles and trailers. Our operating leases relate primarily to real estate.

The table above does not reflect any additional payments that we may be required to make pursuant to contingent earn-out agreements that are associated with certain acquisitions. At December 31, 2007, we had a maximum potential obligation of $25.6 million related to the contingent earn-out agreements. This amount does not include the balance owed for an acquisition with no maximum earn-out exposure. In this situation, we will pay to the sellers an amount for each of the five consecutive 12 month periods equal to 50% of the amount by which annual EBITDA will be reached. See note 3 of the notes to our historical consolidated financial statements for additional detail.

At December 31, 2007, of the $225 million in financial commitments under the revolving line of credit under our senior credit facility, there was only $59.5 million of available capacity due to the outstanding balance of $150 million and the $15.5 million of outstanding standby letters of credit. The 2007 Credit Facility includes provisions allowing us to request an increase in commitments of up to $100 million aggregate principal amount at any time. Additionally, the 2007 Credit Facility permits us to make greater expenditures for acquisitions, capital expenditures and capital leases and to incur greater purchase money obligations, acquisition indebtedness and general unsecured indebtedness.

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

Senior Notes

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

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

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

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

	•		incur additional indebtedness;

	•		pay dividends or repurchase or redeem capital stock;

	•		make certain investments;

	•		incur liens;

	•		enter into certain types of transactions with affiliates;

	•		limit dividends or other payments by restricted subsidiaries; and

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

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

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

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

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

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

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

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

Credit Facilities

2007 Credit Facility

On February 6, 2007, we amended and restated our existing credit agreement by entering into a Fourth Amended and Restated Credit Agreement with a syndicate of lenders (the “2007 Credit Facility”). At December 31, 2007, we had $150 million outstanding under this facility. The amendments contained in the 2007 Credit Facility included:

	•		eliminating the $90 million class of Term B Loans;

	•		creating a new class of Revolving Loans, which increased the lender’s total revolving commitments from $150 million to $225 million

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

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

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

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

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

Under the 2007 Credit Facility, Basic Energy Services, Inc. is the sole borrower and each of our subsidiaries is a subsidiary guarantor. The 2007 Credit Facility provides for a $225 million revolving line of credit (“Revolver”). The 2007 Credit Facility includes provisions allowing us to request an increase in commitments of up to $100 million aggregate principal amount at any time. Additionally, the 2007 Credit Facility permits us to make greater expenditures for acquisitions, capital expenditures and capital leases and to incur greater purchase money obligations, acquisition indebtedness and general unsecured indebtedness. The commitment under the Revolver provides for (1) the borrowing of funds, (2) the issuance of up to $30 million of letters of credit and (3) $2.5 million of swing-line loans. All of the outstanding amounts under the Revolver are due and payable on December 15, 2010. The 2007 Credit Facility is secured by substantially all of our tangible and intangible assets. We incurred approximately $0.7 million in debt issuance costs in connection with the 2007 Credit Facility.

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

0.5% or (2) an “Adjusted LIBOR Rate” (equal to (a) the London Interbank Offered Rate (the “LIBOR rate”) as determined by the Administrative Agent in effect for such interest period divided by (b) one minus the Statutory Reserves, if any, for such borrowing for such interest period) plus a margin ranging from 1.25% to 1.5%. The margins vary depending on our leverage ratio. Fees on the letters of credit are due quarterly on the outstanding amount of the letters of credit at a rate ranging from 1.25% to 1.5% for participation fees and 0.125% for fronting fees. A commitment fee is due quarterly on the available borrowings under the Revolver at a rate of 0.375%.

Pursuant to the 2007 Credit Facility, we must apply proceeds from certain specified events to reduce principal outstanding borrowings under the Revolver, including:

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

	•		100% of the net cash proceeds from any debt issuance, including certain permitted unsecured senior or senior subordinated debt, but excluding certain other permitted debt issuances; and

	•		50% of the net cash proceeds from any equity issuance (including equity issued upon the exercise of any warrant or option).

The 2007 Credit Facility contains various restrictive covenants and compliance requirements, including the following:

	•		limitations on the incurrence of additional indebtedness;

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

	•		limitations on dividends and distributions; and

	•		various financial covenants, including:

	•		a maximum leverage ratio of 3.50 to 1.00, reducing to 3.25 to 1.00 on April 1, 2007, and

	•		a minimum interest coverage ratio of 3.00 to 1.00.

Other Debt

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

Losses on Extinguishment of Debt

In February 2007 and April 2006, Basic recognized a loss on the early extinguishment of debt. In February 2007, Basic wrote off unamortized debt issuance costs of approximately $0.2 million, which related to the 2005 Credit Facility. In April 2006, Basic wrote off unamortized debt issuance costs of approximately $2.7 million, which related to the prepayment of the Term B Loan.

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

Credit Rating Agencies

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

Preferred Stock

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

Other Matters

Net Operating Losses

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

Recent Accounting Pronouncements

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

In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements (SFAS 157), which will become effective for financial assets and liabilities of the company on January 1, 2008 and non-financial assets and liabilities of the company on January 1, 2009. This standard defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. SFAS 157 does not require any new fair value measurements but would apply to assets and liabilities that are required to be recorded at fair value under other accounting standards. The impact, if any, to the company from the adoption of SFAS 157 in 2009 will depend on the company’s assets and liabilities at that time that are required to be measured at fair value.

In February 2007, the FASB issued SFAS 159, The Fair Value Option for Financial Assets and Financial Liabilities (SFAS 159), which becomes effective for the company on January 1, 2008. This standard permits companies to choose to measure many financial instruments and certain other items at fair value and report unrealized gains and losses in earnings. Such accounting is optional and is generally to be applied instrument by instrument. The company does not anticipate that election, if any, of this fair-value option will have a material effect on its results of operations or consolidated financial position.

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

In December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements (SFAS 160), which becomes effective for the company on January 1, 2009. This standard establishes accounting and reporting standards for ownership interests in subsidiaries held by parties other than the parent, the amount of consolidated net income attributable to the parent and to the noncontrolling interest, changes in a parent’s ownership interest and the valuation of retained non-controlling equity investments when a subsidiary is deconsolidated. The Statement also establishes reporting requirements that provide sufficient disclosures that clearly identify and distinguish between the interests of the parent and the interests of the non-controlling owners. The company does not anticipate that this pronouncement will have a material impact on its results of operations or consolidated financial position.

Impact of Inflation on Operations

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