Edgar Filing: BASIC ENERGY SERVICES INC

e10vq

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q


þ		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2006


o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission file number: 1-32693

Basic Energy Services, Inc.

(Exact name of registrant as specified in its charter)


Delaware (State or other jurisdiction of incorporation or organization)		54-2091194 (I.R.S. Employer Identification No.)


400 W. Illinois, Suite 800 Midland, Texas (Address of principal executive offices)		79701 (Zip code)

(432) 620-5500
(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes R No £

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Act). (Check one)


Large Accelerated Filer o		Accelerated Filer o		Non-Accelerated Filer þ

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ

33,787,305 shares of the registrant’s Common Stock were outstanding as of May 10, 2006.

BASIC ENERGY SERVICES, INC.
Index to Form 10-Q


	Page
Part I. FINANCIAL INFORMATION		4
Item 1. Financial Statements		4
Consolidated Balance Sheets as of March 31, 2006 and December 31, 2005		4
Consolidated Statements of Operations and Comprehensive Income for the three months ended March 31, 2006 and 2005		5
Consolidated Statements of Stockholders’ Equity for the three months ended March 31, 2006		6
Consolidated Statements of Cash Flows for the three months ended March 31, 2006 and 2005		7
Notes to Consolidated Financial Statements		8
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operation		23
Management’s Overview		23
Recent Strategic Acquisitions and Expansions		24
Segment Overview		25
Operating Cost Overview		28
Critical Accounting Policies and Estimates		28
Results of Operations		31
Liquidity and Capital Resources		32
Other Matters		35
Item 3. Quantitative and Qualitative Disclosures About Market Risk		36
Item 4. Controls and Procedures		37
Part II. OTHER INFORMATION		38
Item 1. Legal Proceedings		38
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		39
Recent Sales of Unregistered Securities		39
Purchases of Equity Securities by the Issuer and Affiliated Purchasers		39
Item 6. Exhibits		40
Signatures		42
Certification by CEO required by Rule 13a-14a/15d-14a
Certification by CFO required by Rule 13a-14a/15d-14a
Certification by CEO pursuant to Section 906
Certification by CFO pursuant to Section 906

CAUTIONARY STATEMENT
REGARDING FORWARD-LOOKING STATEMENTS

This report contains certain statements that are, or may be deemed to be, “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended, or the Exchange Act. 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 report 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 report are forward looking-statements. Although we believe that the forward-looking statements contained in this report are based upon reasonable assumptions, the forward-looking events and circumstances discussed in this report 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 report. 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.

PART I — FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

Basic Energy Services, Inc.

Consolidated Balance Sheets
(in thousands, except share data)


	March 31,			December 31,
	2006			2005
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	19,953		$	32,845
Trade accounts receivable, net of allowance of $2,984 and $2,775, respectively		101,241			86,932
Accounts receivable — related parties		92			65
Inventories		1,851			1,648
Prepaid expenses		3,790			3,112
Other current assets		2,744			2,060
Deferred tax assets		6,700			6,020


Total current assets		136,371			132,682


Property and equipment, net		399,865			309,075

Deferred debt costs, net of amortization		4,583			4,833
Goodwill		73,201			48,227
Other assets		2,767			2,140

	$	616,787		$	496,957

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	11,376		$	13,759
Accrued expenses		39,711			33,548
Income taxes payable		13,124			7,210
Current portion of long-term debt		8,559			7,646
Other current liabilities		1,328			1,124


Total current liabilities		74,098			63,287


Long-term debt		201,488			119,241
Deferred income		11			17
Deferred tax liabilities		59,956			53,770
Other long-term liabilities		2,993			2,067

Commitments and contingencies

Stockholders’ equity:
Common stock; $.01 par value; 80,000,000 shares authorized; 33,931,935 shares issued; 33,787,305 shares outstanding at March 31, 2006 and 33,785,359 shares outstanding at December 31, 2005, respectively		339			339
Additional paid-in capital		235,264			239,218
Deferred compensation		—			(7,341	)
Retained earnings		46,174			28,654
Treasury stock, 144,630 shares at March 31, 2006, and 146,576 shares at December 31, 2005, respectively, at cost		(3,618	)		(2,531	)
Accumulated other comprehensive income		82			236


Total stockholders’ equity		278,241			258,575

	$	616,787		$	496,957

See accompanying notes to consolidated financial statements.

Basic Energy Services, Inc.

Consolidated Statements of Operations and Comprehensive Income
(Dollars in thousands, except per share amounts)


	Three Months Ended March 31,
	2006			2005
	(Unaudited)
Revenues:
Well servicing	$	73,465		$	44,798
Fluid services		43,121			29,303
Drilling and completion services		27,455			10,764
Well site construction services		10,265			8,948


Total revenues		154,306			93,813

Expenses:
Well servicing		41,610			28,191
Fluid services		26,305			19,238
Drilling and completion services		13,854			5,860
Well site construction services		7,643			7,108
General and administrative, including stock-based compensation of $758 and $591 in 2006 and 2005, respectively		18,005			13,091
Depreciation and amortization		12,837			8,047
(Gain) loss on disposal of assets		(200	)		102


Total expenses		120,054			81,637


Operating income		34,252			12,176

Other income (expense):
Interest expense		(3,138	)		(3,061	)
Interest income		359			101
Other income		27			75


Income from continuing operations before income taxes		31,500			9,291
Income tax expense		(11,819	)		(3,490	)

Net income	$	19,681		$	5,801


Earnings per share of common stock:
Basic	$	0.59		$	0.21


Diluted	$	0.53		$	0.18


Comprehensive Income:
Net income	$	19,681		$	5,801
Unrealized gains (loss) on hedging activities		(154	)		314

Comprehensive Income	$	19,527		$	6,115

See accompanying notes to consolidated financial statements.

Basic Energy Services, Inc.

Consolidated Statements of Stockholders’ Equity
(in thousands, except share data)


																	Accumulated
					Additional												Other			Total
	Common Stock				Paid-In			Deferred			Treasury			Retained			Comprehensive			Stockholders’
	Shares		Amount		Capital			Compensation			Stock			Earnings			Income			Equity
Balance — December 31, 2005		33,931,935	$	339	$	239,218		$	(7,341	)	$	(2,531	)	$	28,654		$	236		$	258,575
Adoption of new accounting standard						(7,341	)		7,341												—
Amortization of deferred compensation						758															758
Unrealized loss on interest rate swap agreement																		(154	)		(154	)
Offering costs						(161	)														(161	)
Purchase of treasury stock												(3,248	)								(3,248	)
Exercise of stock options						2,790						2,161			(2,161	)					2,790
Net income															19,681						19,681

Balance — March 31, 2006 (Unaudited)		33,931,935	$	339	$	235,264		$	—		$	(3,618	)	$	46,174		$	82		$	278,241

See accompanying notes to consolidated financial statements.

Basic Energy Services, Inc.

Consolidated Statements of Cash Flows
( in thousands)


	Three Months Ended March 31,
	2006			2005
	(Unaudited)
Cash flows from operating activities:
Net income	$	19,681		$	5,801
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		12,837			8,047
Accretion on asset retirement obligation		19			9
Change in allowance for doubtful accounts		209			450
Non-cash interest expense		310			263
Non-cash compensation		758			591
(Gain) loss on disposal of assets		(200	)		102
Deferred income taxes		(2,873	)		3,490

Changes in operating assets and liabilities, net of acquisitions:

Accounts receivable		(10,708	)		(2,763	)
Inventories		(18	)		(171	)
Prepaid expenses and other current assets		(1,442	)		(317	)
Other assets		(319	)		(53	)
Accounts payable		(3,169	)		(1,344	)
Excess tax benefits from exercise of employee stock options		(2,790	)		—
Income tax payable		7,449			—
Deferred income and other liabilities		342			(122	)
Accrued expenses		5,829			2,751


Net cash provided by operating activities		25,915			16,734


Cash flows from investing activities:
Purchase of property and equipment		(24,812	)		(16,083	)
Proceeds from sale of assets		1,141			95
Payments for other long-term assets		(393	)		(49	)
Payments for businesses, net of cash acquired		(87,520	)		(3,909	)


Net cash used in investing activities		(111,584	)		(19,946	)


Cash flows from financing activities:
Proceeds from debt		80,000			129
Payments of debt		(6,544	)		(2,938	)
Offering costs related to initial public offering		(161	)		—
Purchase of treasury stock		(1,258	)		—
Excess tax benefits from exercise of employee stock options		2,790			—
Exercise of employee stock options		(1,990	)		—
Deferred loan costs and other financing activities		(60	)		(8	)


Net cash provided by (used in) financing activities		72,777			(2,817	)


Net increase (decrease) in cash and equivalents		(12,892	)		(6,029	)

Cash and cash equivalents — beginning of period		32,845			20,147


Cash and cash equivalents — end of period	$	19,953		$	14,118

See accompanying notes to consolidated financial statements.

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements
March 31, 2006

1. Basis of Presentation and Nature of Operations

Basis of Presentation

The accompanying unaudited consolidated financial statements of Basic Energy Services, Inc. and subsidiaries (“Basic” or the “Company”) have been prepared in accordance with accounting principles generally accepted in the United States for interim financial reporting. Accordingly, they do not include all of the information and footnotes required by accounting principles generally accepted in the United States for complete financial statements. In the opinion of management, all adjustments considered necessary for a fair presentation have been made in the accompanying unaudited financial statements.

Nature of Operations

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

BASIC ENERGY SERVICES, INC.
Notes to Consolidated Financial Statements
March 31, 2006

2. Summary of Significant Accounting Policies

Principles of Consolidation

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

Revenue Recognition

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

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

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

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

Impairments

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

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

Basic had no impairment expense in the three months ended March 31, 2006 and 2005, respectively.

BASIC ENERGY SERVICES, INC.
Notes to Consolidated Financial Statements
March 31, 2006

Deferred Debt Costs

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

Deferred debt costs of approximately $7.1 million at March 31, 2006 and $7.0 million at December 31, 2005, respectively, represent debt issuance costs and are recorded net of accumulated amortization of $2.5 million, and $2.2 million at March 31, 2006 and December 31, 2005, respectively. Amortization of deferred debt costs totaled approximately $311,000 and $263,000 for the three months ended March 31, 2006 and 2005, respectively.

Goodwill

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

Basic has identified its reporting units to be well servicing, fluid services, drilling and completion services and well site construction services. The goodwill allocated to such reporting units as of March 31, 2006 is $9.9 million, $30.7 million, $28.9 million and $3.7 million, respectively. The change in the carrying amount of goodwill for the three months ended March 31, 2006 of $25.0 million relates to goodwill from acquisitions and payments pursuant to contingent earn-out agreements, with approximately $10.1 million and $14.9 million of goodwill additions relating to the fluid services and drilling and completion units, respectively.

Stock-Based Compensation

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

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

BASIC ENERGY SERVICES, INC.
Notes to Consolidated Financial Statements
March 31, 2006

Under SFAS No. 123R, entities using the minimum value method and the prospective application are not permitted to provide the pro forma disclosures (as was required under Statement of Financial Accounting Standard No. 123, “Accounting for Stock-Based Compensation” (“SFAS No. 123”)) subsequent to adoption of SFAS 123R since they do not have the fair value information required by SFAS No. 123R. Therefore, in accordance with 123R, Basic will no longer include pro forma disclosures that were required by SFAS 123.

Asset Retirement Obligations

Basic owns and operates salt water disposal sites, brine water wells, gravel pits and land farm sites, each of which is subject to rules and regulations regarding usage and eventual closure. The following table reflects the changes in the liability during the three months ended March 31, 2006 (in thousands):


Balance, December 31, 2005	$	569

Additional asset retirement obligations recognized through acquisitions		118
Accretion Expense		19
Increase in asset retirement obligations due to change in estimate		295


Balance, March 31, 2006 (unaudited)	$	1,001

Environmental

Basic is subject to extensive federal, state and local environmental laws and regulations. These laws, which are constantly changing, regulate the discharge of materials into the environment and may require Basic to remove or mitigate the adverse environmental effects of disposal or release of petroleum, chemical and other substances at various sites. Environmental expenditures are expensed or capitalized depending on the future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Liabilities for expenditures of a non-capital nature are recorded when environmental assessment and/or remediation is probable and the costs can be reasonably estimated.

Litigation and Self-Insured Risk Reserves

Basic estimates its reserves related to litigation and self-insured risks based on the facts and circumstances specific to the litigation and self-insured claims and its past experience with similar claims in accordance with Statement of Financial Accounting Standard No. 5 “Accounting for Contingencies”. Basic maintains accruals in the consolidated balance sheets to cover self-insurance retentions (See note 6).

Recent Accounting Pronouncements

In December 2004, the Financial Accounting Standards Board issued SFAS No. 123R. As discussed under this Note 2, “Stock-Based Compensation,” Basic adopted the provisions of SFAS No. 123R on January 1, 2006.

BASIC ENERGY SERVICES, INC.
Notes to Consolidated Financial Statements
March 31, 2006

3. Acquisitions

In 2006 and 2005, Basic acquired either substantially all of the assets or all of the outstanding capital stock of each of the following businesses, each of which were accounted for using the purchase method of accounting (in thousands):


		Total Cash Paid
		(net of cash
	Closing Date	acquired)
R & R Hot Oil Service	January 5, 2005	$	1,702
Premier Vacuum Service, Inc.	January 28, 2005		1,009
Spencer’s Coating Specialist	February 9, 2005		619
Mark’s Well Service	February 25, 2005		579
Max-Line, Inc.	April 28, 2005		1,498
MD Well Service, Inc.	May 17, 2005		4,478
179 Disposal, Inc.	August 4, 2005		1,729
Oilwell Fracturing Services, Inc.	October 11, 2005		13,764


Total 2005		$	25,378


LeBus Oil Field Services Co.	January 31, 2006	$	24,508
G&L Tool, Ltd.	February 28, 2006		58,000
Arkla Cementing, Inc.	March 27, 2006		5,012


Total 2006		$	87,520

Contingent Earn-out Arrangements and Final Purchase Price Allocations

Contingent earn-out arrangements are generally arrangements entered in certain acquisitions to encourage the owner/manager to continue operating and building the business after the purchase transaction. The contingent earn-out arrangements of the related acquisitions are generally linked to certain financial measures and performance of the assets acquired in the various acquisitions. All amounts paid or reasonably accrued for related to the contingent earn-out payments are reflected as increases to the goodwill associated with the acquisition.

On February 28, 2006, Basic acquired substantially all of the assets of G&L Tool for $58.0 million plus a contingent earn-out payment not to exceed $21.0 million. The contingent earn out payment will be equal to fifty percent of the amount by which the annual EBITDA earned by Basic exceeds an annual targeted EBITDA. There is no guarantee or assurance that the targeted EBITDA will be reached. This acquisition provided a platform to expand into the fishing and rental tool market operations. The cost of the G&L acquisition was allocated $43.3 million to property and equipment, $14.6 million to goodwill, and $51,000 to non-compete agreements. The allocations of the purchase price are based upon preliminary estimates and assumptions. Accordingly, the allocations are subject to revision when the Company receives final information, including appraisals and other analyses. Revisions to the fair values, which may be significant, will be recorded by the Company as further adjustments to the purchase price allocations.

BASIC ENERGY SERVICES, INC.
Notes to Consolidated Financial Statements
March 31, 2006

The following unaudited pro-forma results of operations have been prepared as though the G&L Tool acquisition had been completed on January 1, 2005. Pro forma amounts are based on the preliminary purchase price allocations of the significant acquisitions and are not necessarily indicative of the results that may be reported in the future (in thousands, except per share data).


	Three Months Ended
	March 31,
	2006		2005
	(Unaudited)
Revenues	$	163,799	$	101,482

Net income	$	22,145	$	7,296

Earnings per common share — basic	$	0.67	$	0.26
Earnings per common share — diluted	$	0.60	$	0.23

Basic does not believe the pro-forma effect of the remainder of the acquisitions completed in 2005 or 2006 is material, either individually or when aggregated, to the reported results of operations.

4. Property and Equipment

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


	March 31,		December 31,
	2006		2005
	(Unaudited)
Land	$	2,108	$	1,902
Buildings and improvements		10,418		8,634
Well service units and equipment		217,086		199,070
Fluid services equipment		72,797		59,104
Brine and fresh water stations		7,773		7,746
Frac/test tanks		43,425		31,475
Pressure pumping equipment		38,479		31,101
Construction equipment		25,013		24,224
Disposal facilities		21,685		16,828
Vehicles		25,382		23,329
Rental equipment		47,906		6,519
Aircraft		3,236		3,236
Other		8,473		8,602

		523,781		421,770
Less accumulated depreciation and amortization		123,916		112,695

Property and equipment, net	$	399,865	$	309,075

BASIC ENERGY SERVICES, INC.
Notes to Consolidated Financial Statements
March 31, 2006

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):


	March 31,		December 31,
	2006		2005
	(Unaudited)
Light vehicles	$	19,564	$	17,912
Fluid services equipment		14,662		14,011
Construction equipment		3,156		1,300

		37,382		33,223
Less accumulated amortization		9,535		8,474

	$	27,847	$	24,749

Amortization of assets held under capital leases of approximately $1,060,000 and $253,000 for the three months ended March 31, 2006 and 2005, respectively, is included in depreciation and amortization expense in the consolidated statements of operations.

5. Long-Term Debt

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


	March 31,		December 31,
	2006		2005
	(Unaudited)
Credit Facilities:
Term B Loan	$	89,750	$	90,000
Revolver		96,000		16,000
Capital leases and other notes		24,297		20,887

		210,047		126,887
Less current portion		8,559		7,646

	$	201,488	$	119,241

2005 Credit Facility

On December 15, 2005, Basic entered into a $240 million Third Amended and Restated Credit Agreement with a syndicate of lenders (“2005 Credit Facility”), which refinanced all of its then existing credit facilities. The 2005 Credit Facility, as amended effective March 28, 2006, provides for a $90 million Term B Loan (“2005 Term B Loan”) and a $150 million revolving line of credit (“Revolver”). The commitment under the Revolver allows for (a) the borrowing of funds (b) issuance of up to $30 million of letters of credit and (c) $2.5 million of swing-line loans (next day borrowing). The amounts outstanding under the 2005 Term B Loan require quarterly amortization at various amounts during each quarter with all amounts outstanding on December 15, 2011 being due and payable in full. All the outstanding amounts under the Revolver are due and payable on December 15, 2010. The 2005 Credit Facility is secured by substantially all of Basic’s tangible and intangible assets. Basic incurred approximately $1.8 million in debt issuance costs in obtaining the 2005 Credit Facility.

At Basic’s option, borrowings under the 2005 Term B Loan bear interest at either the (a) “Alternative Base Rate” (i.e. the higher of the bank’s prime rate or the federal funds rate plus .5% per annum) plus 1% or (b) the LIBOR rate plus 2.0%. At March 31, 2006 and December 31, 2005, Basic’s weighted average interest rate on its Term B Loan was 7.1% and 6.4%.

BASIC ENERGY SERVICES, INC.
Notes to Consolidated Financial Statements
March 31, 2006

At Basic’s option, borrowings under the 2005 Revolver bear interest at either the (a) “Alternative Base Rate” (i.e. the higher of the bank’s prime rate or the federal funds rate plus ..5% per annum) plus a margin ranging from .50% to 1.25% or (b) the LIBOR rate plus a margin ranging from 1.5% to 2.25%. The margins vary depending on Basic’s leverage ratio. At March 31, 2006, Basic’s margin on Alternative Base Rates and LIBOR tranches was .75% and 1.75%, respectively. Fees on the letters of credit are due quarterly on the outstanding amount of the letters of credit at a rate ranging from 1.5% to 2.25% for participation fees and .125% for fronting fees. A commitment fee is due quarterly on the available borrowings under the Revolver at rates ranging from .375% to ..5%.

At March 31, 2006 Basic, under its Revolver, had outstanding $96 million of borrowings and $9.6 million of letters of credit and no amounts outstanding in swing-line loans. At March 31, 2006 and December 31, 2005 Basic had availability under its Revolver of $44.4 million and $124.4 million, respectively.

Pursuant to the 2005 Credit Facility, Basic must apply proceeds to reduce principal outstanding under the 2005 Term B Revolver from (a) individual assets sales greater than $2 million or $7.5 million in the aggregate on an annual basis, and (b) 50% of the proceeds from any equity offering. The 2005 Credit Facility required Basic to enter into an interest rate hedge, through May 28, 2006 on at least $65 million of Basic’s then outstanding indebtedness. The March 28, 2006 amendment deletes this requirement upon payoff of the Term B Loans. Paydowns on the 2005 Term B Loan may not be reborrowed.

The 2005 Credit Facility contains various restrictive covenants and compliance requirements, which include (a) limiting of the incurrence of additional indebtedness, (b) restrictions on mergers, sales or transfers of assets without the lenders’ consent, (c) limitation on dividends and distributions and (d) various financial covenants, including (1) a maximum leverage ratio of 3.5 to 1.0 reducing over time to 3.25 to 1.0, (2) a minimum interest coverage ratio of 3.0 to 1.0 and (e) limitations on capital expenditures in any period of four consecutive quarters in excess of 20% of Consolidated Net Worth unless certain criteria are met. At March 31, 2006 and December 31, 2005, Basic was in compliance with its covenants.

Other Debt

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

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


	Three Months Ended
	March 31,
	2006		2005
	(Unaudited)
Cash payments for interest	$	1,942	$	2,723
Commitment and other fees paid		148		—
Amortization of debt issuance costs		311		263
Other		737		75

	$	3,138	$	3,061

BASIC ENERGY SERVICES, INC.
Notes to Consolidated Financial Statements
March 31, 2006

6. Commitments and Contingencies

Environmental

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

Currently, Basic has not been fined, cited or notified of any environmental violations that would have a material adverse effect upon its financial position, liquidity or capital resources. However, management does recognize that by the very nature of its business, material costs could be incurred in the near term to bring Basic into total compliance. The amount of such future expenditures is not determinable due to several factors including the unknown magnitude of possible contamination, the unknown timing and extent of the corrective actions which may be required, the determination of Basic’s liability in proportion to other responsible parties and the extent to which such expenditures are recoverable from insurance or indemnification.

Litigation

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

Self-Insured Risk Accruals

Basic is self-insured up to retention limits as it relates to workers’ compensation and medical and dental coverage of its employees. Basic, generally, maintains no physical property damage coverage on its workover rig fleet, with the exception of certain of its 24-hour workover rigs and newly manufactured rigs. Basic has deductibles per occurrence for workers’ compensation and medical and dental coverage of $150,000 and $125,000, respectively. Basic has lower deductibles per occurrence for automobile liability and general liability. Basic maintains accruals in the accompanying consolidated balance sheets related to self-insurance retentions by using third-party data and historical claims history.

At March 31, 2006 and December 31, 2005, self-insured risk accruals, net of related recoveries/receivables totaled approximately $11.4 million and $9.5 million, respectively.

7. Stockholders’ Equity

Common Stock

In February 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.

BASIC ENERGY SERVICES, INC.
Notes to Consolidated Financial Statements
March 31, 2006

In February 2004, Basic granted certain officers and directors 837,500 restricted shares of common stock. The shares vest 25% per year for four years from the award date and are subject to other vesting and forfeiture provisions. The estimated fair value of the restricted shares was $5.8 million at the date of the grant and was recorded as deferred compensation, a component of stockholders’ equity. This amount is being charged to expense over the respective vesting period and totaled approximately $379,000 and $409,000 for the three months ended March 31, 2006 and 2005, respectively.

In December 2005, Basic issued 5,000,000 shares of common stock during the Company’s Initial Public Offering to a group of investors for $100 million or $20 per share. After deducting fees, this resulted in net proceeds to Basic totaling approximately $91.5 million.

In March 2006, Basic issued 148,720 shares of common stock from treasury stock for the exercise of stock options.

8. Incentive Plan

In May 2003, Basic’s board of directors and stockholders approved the Basic 2003 Incentive Plan (as amended effective April 22, 2005), (the “Plan”) which provides for granting of incentive awards in the form of stock options, restricted stock, performance awards, bonus shares, phantom shares, cash awards and other stock-based awards to officers, employees, directors and consultants of Basic. The Plan assumed awards of the plans of Basic’s successors that were awarded and remained outstanding prior to adoption of the Plan. The Plan provides for the issuance of 5,000,000 shares. The Plan is administered by the Plan committee, and in the absence of a Plan committee, by the Board of Directors, which determines the awards, and the associated terms of the awards and interprets its provisions and adopts policies for implementing the Plan. The number of shares authorized under the Plan and the number of shares subject to an award under the Plan will be adjusted for stock splits, stock dividends, recapitalizations, mergers and other changes affecting the capital stock of Basic.

On March 15, 2006, the board of directors granted various employees options to purchase 418,000 shares, respectively, of common stock of Basic at exercise prices of $26.84 per share, respectively. All of the 418,000 options granted in 2006 vest over a five-year period and expire 10 years from the date they were granted. Option awards are generally granted with an exercise price equal to the market price of the Company’s stock at the date of grant.

The fair value of each option award is estimated on the date of grant using the Black-Scholes-Merton option-pricing model that uses the subjective assumptions noted in the following table. Since the Company has only been public since December 2005, expected volatilities are based upon a peer group. When the Company has sufficient historical data to calculate expected volatility, the Company will use its’ own historical data to calculate expected volatility. The expected term of options granted represents the period of time that options granted are expected to be outstanding. The risk-free rate for periods within the contractual life of the options is based on the U.S. Treasury yield curve in effect at the time of grant. The estimates involve inherent uncertainties and the application of management judgment. In addition, we are required to estimate the expected forfeiture rate and only recognize expense for those options expected to vest. Compensation expense related to share-based arrangements was approximately $758,000 and $591,000 during the three months ended March 31, 2006 and 2005, respectively.

The fair value of each option award accounted for under FAS No. 123R is estimated on the date of grant using the Black-Scholes-Merton option-pricing model that uses the assumptions noted in the following table:


	Three Months
	Ended March
	31, 2006
Risk-free interest rate		4.7	%
Expected term		6.65
Expected volatility		47.0	%
Expected dividend yield		—

BASIC ENERGY SERVICES, INC.
Notes to Consolidated Financial Statements
March 31, 2006

Options granted under the Plan expire 10 years from the date they are granted, and generally vest over a three to five year service period.

The following table reflects the summary of stock options outstanding for the three months ended March 31, 2006 and the changes during the three months then ended:


				Weighted		Aggregate
	Number of			Average		Instrinsic
	Options			Exercise		Value
	Granted			Price		(000’s)
Non-statutory stock options:
Outstanding beginning of period		2,445,800		$	5.44		—
Options granted		418,000		$	26.84		—
Options forfeited		(10,000	)	$	6.98		—
Options exercised		(148,720	)	$	4.00		—

Outstanding, end of period		2,705,080		$	8.82	$	52,866


Exercisable, end of period		1,277,913		$	4.16	$	32,769


Expected to vest, end of period		1,391,469		$	12.64	$	23,883

The following table summarizes information about Basic’s stock options outstanding and options exercisable at March 31, 2006:


		Options Outstanding						Options Exercisable
Range		Number of		Weighted		Weighted		Number of		Weighted		Weighted
of		Options		Average		Average		Options		Average		Average
Exercise		Outstanding at		Remaining		Exercise		Outstanding at		Remaining		Exercise
Prices		March 31, 2006		Contractual Life		Price		March 31, 2006		Contractual Life		Price
$	4.00		1,104,580		6.20	$	4.00		1,104,580		6.20	$	4.00
$	5.16		310,000		8.23	$	5.16		173,333		8.12	$	5.16
$	6.98		835,000		8.92	$	6.98		—			$	—
$	21.01		37,500		9.71	$	21.01		—			$	—
$	26.84		418,000		9.96	$	26.84		—			$	—

			2,705,080						1,277,913

The weighted-average grant date fair value of share options granted during the three months ended March 31, 2006 and 2005 was $14.47 and $8.10, respectively. The total intrinsic value of share options exercised during the three months ended March 31, 2006 and 2005 was approximately $3.4 million and $0, respectively.

BASIC ENERGY SERVICES, INC.
Notes to Consolidated Financial Statements
March 31, 2006

A summary of the status of the Company’s non-vested share grants at March 31, 2006 and changes during the three months ended March 31, 2006 is presented in the following table:


				Weighted Average
	Number of			Grant Date Fair
Nonvested Shares	Shares			Value Per Share
Nonvested at beginning of period		591,875		$	6.98
Granted during period		—			—
Vested during period		(230,625	)		6.98
Forfeited during period		—			—

Nonvested at end of period		361,250		$	6.98

As of March 31, 2006, there was $12.2 million of total unrecognized compensation related to non-vested share-based compensation arrangements granted under the Plan. That cost is expected to be recognized over a weighted-average period of 3.78 years. The total fair value of shares vested during the three months ended March 31, 2006 and 2005 was approximately $15.4 million and $6.2 million, respectively.

Cash received from share option exercises under the incentive plan was $0 for the three months ended March 31, 2006 and 2005, respectively. The actual tax benefit realized for the tax deductions from option exercise is $2.8 million and $0, respectively, for the three months ended March 31, 2006 and 2005.

9. Related Party Transactions

Basic had receivables from employees of approximately $92,000 and $65,000 as of March 31, 2006 and December 31, 2005, respectively.

10. Earnings Per Share

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


	Three Months Ended March 31,
	2006		2005
	(Unaudited)
Numerator (both basic and diluted):
Net income	$	19,681	$	5,801

Denominator:

Denominator for basic earnings per share		33,261,539		28,186,147

Stock options		1,093,089		571,182
Unvested restricted stock		256,238		603,125
Common stock warrants		2,291,362		2,796,706


Denominator for diluted earnings per share		36,902,228		32,157,160


Basic earnings per common share	$	.59	$	.21


Diluted earnings per common share	$	.53	$	.18

BASIC ENERGY SERVICES, INC.
Notes to Consolidated Financial Statements
March 31, 2006

11. Business Segment Information

Basic’s reportable business segments are well servicing, fluid services, drilling and completion services and well site construction services. The following is a description of the segments:

Well Servicing: This business segment encompasses a full range of services performed with a mobile well servicing rig, including the installation and removal of downhole equipment and elimination of obstructions in the well bore to facilitate the flow of oil and gas. These services are performed to establish, maintain and improve production throughout the productive life of an oil and gas well and to plug and abandon a well at the end of its productive life. Basic well servicing equipment and capabilities are essential to facilitate most other services performed on a well.

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

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

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

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

BASIC ENERGY SERVICES, INC.
Notes to Consolidated Financial Statements
March 31, 2006

operating segments. Corporate assets consist principally of working capital and debt financing costs. The following table sets forth certain financial information with respect to Basic’s reportable segments (in thousands):


							Drilling and			Well Site
	Well			Fluid			Completion			Construction			Corporate
	Servicing			Services			Services			Services			and Other		Total
*Three Months Ended March 31, 2006*
(Unaudited)
Operating revenues	$	73,465		$	43,121		$	27,455		$	10,265		$	—	$	154,306
Direct operating costs		(41,610	)		(26,305	)		(13,854	)		(7,643	)		—		(89,412	)

Segment profits	$	31,855		$	16,816		$	13,601		$	2,622		$	—	$	64,894


Depreciation and amortization	$	5,694		$	3,520		$	2,321		$	830		$	472	$	12,837
Capital expenditures, (excluding acquisitions)	$	11,005		$	6,804		$	4,485		$	1,604		$	914	$	24,812
Identifiable assets	$	185,390		$	138,969		$	106,264		$	29,747		$	156,417	$	616,787

*Three Months Ended March 31, 2005*
(Unaudited)
Operating revenues	$	44,798		$	29,303		$	10,764		$	8,948		$	—	$	93,813
Direct operating costs		(28,191	)		(19,238	)		(5,860	)		(7,108	)		—		(60,397	)

Segment profits	$	16,607		$	10,065		$	4,904		$	1,840		$	—	$	33,416


Depreciation and amortization	$	4,094		$	2,332		$	531		$	653		$	437	$	8,047
Capital expenditures, (excluding acquisitions)	$	8,182		$	4,660		$	1,061		$	1,306		$	874	$	16,083
Identifiable assets	$	134,569		$	90,003		$	25,400		$	24,213		$	104,283	$	378,468

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


	Three Months Ended March 31,
	2006			2005
Segment profits	$	64,894		$	33,416

General and administrative expenses		(18,005	)		(13,091	)
Depreciation and amortization		(12,837	)		(8,047	)
Gain (loss) on disposal of assets		200			(102	)


Operating income	$	34,252		$	12,176

12. Supplemental Schedule of Cash Flow Information:

The following table reflects non-cash financing and investing activity during:


	Three Months Ended March 31,
	2006		2005
	(In thousands)
Capital leases issued for equipment	$	5,203	$	1,032
Asset retirement obligation additions	$	413	$	—

BASIC ENERGY SERVICES, INC.
Notes to Consolidated Financial Statements
March 31, 2006

Basic paid income taxes of approximately $6.9 million and $0 during the three months ended March 31, 2006 and 2005, respectively.

13. Subsequent Events

(a) Debt Offering

In April 2006, the Company completed a private offering for $225,000,000 aggregate principal amount of 7.125% Senior Notes due April 15, 2016. The net proceeds from the offering were used to retire the outstanding Term B Loan balance and to repay current borrowings under the revolving credit facility. Any remaining proceeds will be used for general corporate purposes.

In connection with the retirement of the Term B Loan on April 13, 2006, we will expense remaining unamortized deferred debt issuance costs which amounted to approximately $2.7 million, net.

ITEM 2. 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, 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 11 separate acquisitions from January 1, 2005 to March 31, 2006. Our weighted average number of well servicing rigs has increased from 291 in the first quarter of 2005 to 327 in the first quarter of 2006, and our weighted average number of fluid service trucks has increased from 435 to 529 in the same period.

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


	Three Months Ended March 31,
	2006				2005
Revenues:
Well servicing	$	73.5	47	%	$	44.8	48	%
Fluid services		43.1	28	%		29.3	31	%

Drilling and completion services		27.4	18	%		10.8	11	%
Well site construction services		10.3	7	%		8.9	10	%

Total revenues	$	154.3	100	%	$	93.8	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.

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.

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

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

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

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

•

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

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

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

Recent Strategic Acquisitions and Expansions

During 2005, we continued to direct our focus for growth more on the integration and expansion of our existing businesses, through capital expenditures and to a lesser extent, acquisitions. During the first quarter of 2006, we completed three additional acquisitions, one of which was significant.

We discuss the aggregate purchase prices and related financing issues below in “- Liquidity and Capital Resources” and present the pro-forma effects of certain significant acquisitions in the historical financial statements included with this report.

Selected 2005 Acquisitions

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

MD Well Service, Inc.

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

Oilwell Fracturing Services, Inc.

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

Selected 2006 Acquisitions

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

LeBus Oil Field Service Co.

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

G&L Tool, Ltd.

On February 28, 2006, we acquired substantially all of the operating assets of G&L Tool, Ltd. (G&L) for total consideration of $58 million cash. This acquisition will operate in our drilling and completion line of business. The purchase agreement also contained an earn-out agreement based on annual EBITDA targets. The cash used to acquire G&L was primarily from borrowings under our senior credit facility.

Segment Overview

Well Servicing

During the first three months of 2006, our well servicing segment represented 47% of our total revenues. Revenue in our well servicing segment is derived from maintenance, workover, completion and plugging and abandonment services. We provide maintenance-related services as part of the normal, periodic upkeep of producing oil and gas wells. Maintenance-related services represent a relatively consistent component of our business. Workover and completion services generate more revenue per hour than maintenance work due to the use of auxiliary equipment, but demand for workover and completion services fluctuates more with the overall activity level in the industry.

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

The following is an analysis of our well servicing operations for each of the quarters ended December 31, 2005 and the quarter ended March 31, 2006:


	Weighted									Segment
	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		84.30	%	$	255	$	94		37.10	%
Second Quarter		303		192,400		88.80	%	$	280	$	107		38.20	%
Third Quarter		311		198,000		89.00	%	$	299	$	108		36.00	%
Fourth Quarter		316		195,000		86.30	%	$	329	$	134		40.70	%
2006:
First Quarter		327		209,000		89.4	%	$	352	$	152		43.4	%

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

Improving market conditions since the first quarter of 2005 have created increased demand for our services. Rig hours have increased due to a combination of the improved utilization of our well servicing rigs and the expansion of our well servicing fleet as a result of our newbuild rig program.

We have been able to increase our revenue per rig hour from $255 in the first quarter of 2005 to $352 in the first quarter of 2006 mainly as a result of this higher utilization, which has contributed to our improved segment profits.

Fluid Services

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

The following is an analysis of our fluid services operations for each of the quarters ended December 31, 2005 and the quarter ended March 31, 2006 (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	$	67	$	24		34.30	%
Second Quarter		447	$	71	$	26		37.00	%
Third Quarter		465	$	74	$	28		38.60	%
Fourth Quarter		472	$	79	$	31		39.80	%
2006:
First Quarter		529	$	82	$	32		39.0	%

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

The majority of the increase in revenue per fluid services truck from $67,000 in the first quarter of 2005 to $82,000 in the first quarter of 2006 is due to the revenues derived from the expansion of our frac tank fleet and

disposal facilities as well as increases in prices charged for our services. Our segment profits per fluid services truck have increased because of these factors and increased utilization of our equipment.

Drilling and Completion Services

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

Our pressure pumping operations concentrate on providing single-truck, lower horsepower cementing, acidizing and fracturing services in selected markets. We entered the fishing and rental tool business through our acquisition of G&L in the first quarter of 2006.

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

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


			Segment
	Revenues		Profits %
2005
First Quarter	$	10,764		45.60	%
Second Quarter	$	13,512		49.10	%
Third Quarter	$	15,883		48.20	%
Fourth Quarter	$	19,673		49.50	%
2006
First Quarter	$	27,455		49.50	%

We gauge the performance of our drilling and completion services segment based on the segment’s operating revenues and segment profits. Improved market conditions since the first quarter of 2005 have enabled us to increase our pricing for these services, contributing to the improved segment profits as a percentage of segment revenues.

Well Site Construction Services

During the first three months of 2006, our well site construction services segment represented 7% of our revenues. Revenues from our well site construction services segment are derived primarily from preparing and maintaining access roads and well locations, installing small diameter gathering lines and pipelines, constructing foundations to support drilling rigs and providing maintenance services for oil and gas facilities. These services are independent of our other services and, while offered to some customers utilizing other services, are not offered on a bundled basis.

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

The following is an analysis of our well site construction services for each of the quarters ended December 31, 2005 and the quarter ended March 31, 2006 (dollars in thousands):


			Segment
	Revenues		Profits %
2005
First Quarter	$	8,948		20.6	%
Second Quarter	$	10,918		30.8	%
Third Quarter	$	11,367		31.6	%
Fourth Quarter	$	14,414		33.6	%
2006
First Quarter	$	10,265		25.5	%

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

Operating Cost Overview

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

Critical Accounting Policies and Estimates

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

Impairments. We review our assets for impairment at a minimum annually, or whenever, in management’s judgment, events or changes in circumstances indicate that the carrying amount of a long-lived asset may not be recovered over its remaining service life. Provisions for asset impairment are charged to income when the sum of the

estimated future cash flows, on an undiscounted basis, is less than the assets’ carrying amount. When impairment is indicated, an impairment charge is recorded based on an estimate of future cash flows on a discounted basis.

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

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

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

Critical Accounting Estimates

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

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

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

Allowance for Doubtful Accounts. We estimate our allowance for doubtful accounts based on an analysis of historical collection activity and specific identification of overdue accounts. Factors that may affect this estimate include (1) changes in the financial 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.

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

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

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

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

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 loss carryforwards are available to us, no assurance can be given concerning the realization of such loss carryforwards, or whether or not such loss carryforwards will be available in the future.

Asset Retirement Obligations. SFAS No. 143 requires us to record the fair value of an asset retirement obligation as a liability in the period in which it 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.

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

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

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

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

Drilling and completion services revenue increased 155% to $27.5 million during the first quarter in 2006 as compared to $10.8 million in the same period in 2005. The increase in revenue between these periods was primarily the result of internal expansion, the acquisition of Oilwell Fracturing Services in October 2005, the acquisition of G&L during February 2006 and improved pricing and utilization of our services.

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

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

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

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

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

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

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

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

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

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

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

Liquidity and Capital Resources

Our primary capital resources are currently 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 $44.4 million was available at March 31, 2006. As of March 31, 2006, we had cash and cash equivalents of $20.0 million compared to $14.1 million as of March 31, 2005. We have utilized, and expect to utilize in the future, bank and capital lease financing and sales of equity to obtain capital resources. When appropriate, we will consider public or private debt and equity offerings and non-recourse transactions to meet our liquidity needs.

Net Cash Provided by Operating Activities

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

Capital Expenditures

Capital expenditures are the main component of our investing activities. Cash capital expenditures (including for acquisitions) for the first quarter in 2006 were $112.3 million as compared to $20.0 million for the same period in 2005. In 2006 and 2005, the majority of our capital expenditures were for the expansion of our fleet. We also added assets through our capital lease program of approximately $5.2 million in the first quarter in 2006 compared to $1.0 million in the same period in 2005.

For 2006, we currently have planned approximately $93 million in cash capital expenditures, none of which is planned for acquisitions. We do not budget acquisitions in the normal course of business, but we completed three acquisitions for total consideration paid of $87.5 million, net of cash acquired during the first quarter of 2006 and expect to make additional acquisitions in 2006. The $93 million of capital expenditures planned for property and equipment is primarily for (1) purchase of additional equipment to expand our services, (2) continued refurbishment of our well servicing rigs and (3) replacement of existing equipment. We have taken delivery of 45 newbuild will servicing rigs since October 2004 as part of a 102-rig newbuild commitment. The remainder of these newbuilds is scheduled to be delivered to us prior to the end of December 2007. As of March 31, 2006, we had no executed letters of intent. However, on April 26, 2006, we signed a letter of intent related to the acquisition of three related entities totaling approximately $10 million.

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

Capital Resources and Financing

Our current primary capital resources are cash flow from our operations, the ability to enter into capital leases of up to an additional $25.7 million at March 31, 2006, the availability under our credit facility of $44.4 million at March 31, 2006 and a cash balance of $20.0 million at March 31, 2006. During the first quarter in 2006, we financed activities in excess of cash flow from operations primarily through the use of bank debt and capital leases.

At March 31, 2006, of the $150.0 million in financial commitments under the revolving line of credit under our senior credit facility, there was only $44.4 million of available capacity due to the outstanding balance of $96.0 million and the $9.6 million of outstanding standby letters of credit. In the normal course of business, we have performance obligations which are supported by surety bonds and letters of credit. These obligations primarily cover various reclamation and plugging obligations related to our operations, and collateral for future workers compensation and liability retained losses.

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

Senior Notes

In April 2006, the Company completed a private offering for $225,000,000 aggregate principal amount of 7.125% Senior Notes due April 15, 2016 (Senior Notes). The net proceeds from the offering were used to retire the outstanding Term B Loan balance and to pay down the outstanding balance under the revolving credit facility. Remaining proceeds will be used for general corporate purposes, including acquisitions. The summary description of the Senior Notes set forth in Item 2.03 of our Form 8-K filed on April 13, 2006 is incorporated herein by reference.

2005 Credit Facility

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

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

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

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

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

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

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

	•		50% of the proceeds from any equity offering;

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

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

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

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

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

	•		limitations on the incurrence of additional indebtedness;

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

	•		limitation on dividends and distributions;

	•		limitations on capital expenditures; and

	•		various financial covenants, including:

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

	•		a minimum interest coverage ratio of 3.00 to 1.00.

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

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 March 31, 2006, we had total capital leases of approximately $24.3 million.

Credit Rating Agencies

Effective November 22, 2005, we received credit ratings of Ba3 from Moody’s and B+ from Standard & Poor’s for the 2005 Credit Facility.

We received initial credit ratings of B1 from Moody’s and B from Standard & Poor’s for the Senior Notes issued in April 2006.

None of our debt or other instruments is dependent upon our credit ratings. However, the credit ratings may affect our ability to obtain financing in the future.

Other Matters

Net Operating Losses

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

Recent Accounting Pronouncements

See discussion above in “Critical Accounting Estimates” and note 2 of the notes to the unaudited consolidated financial statements included under Item 1 of this quarterly report regarding Statement of Financial Accounting Standard 123 (revised 2004) Share-based Payment.

Impact of Inflation on Operations

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

ITEM 3. 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 $106 million of indebtedness outstanding under our credit facility at December 31, 2005. The impact of a 1% increase in interest rates on this amount of debt would result in increased interest expense (excluding effects of our interest rate hedges) of approximately $1.1 million annually, or a decrease in net income of approximately $687,000.

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 2005 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, 2005 (dollars in thousands):


	Expected Year of Maturity
	2006		2007		2008		2009		2010		Thereafter		Total		Fair Value
Debt
Variable rate	$	1,000	$	1,000	$	1,000	$	1,000	$	17,000	$	85,000	$	106,000	$	106,000
Average interest rate(1)


	Average Notional Amounts Outstanding (2)
	2006			2007		2008		2009		2010		Thereafter		Total			Fair Value
Interest Rate Derivatives
Variable to Fixed	$	26,356			—		—		—		—		—	$	26,356		$	422
Average pay rate		3.03	%		—		—		—		—		—		3.03	%		N/A
Average received rate		4.83	%		—		—		—		—		—		4.83	%		N/A


(1)		At our option, borrowings under the 2005 Revolver bear interest at either (a) the “Alternative Base Rate” (i.e. the higher of the bank’s prime rate or the federal funds rate plus .5% per annum) plus a margin ranging from .50% to 1.25% or (b) the LIBOR rate plus a margin ranging from 1.5% to 2.25%. The margins vary depending on our leverage ratio. At December 31, 2005, our margin on Alternative Base Rates and LIBOR tranches was .75% and 1.75%, respectively.

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

ITEM 4. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

Based on their evaluation as of the end of the three months ended March 31, 2006, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) are effective to ensure that information required to be disclosed in reports that we file or submit under the Exchange Act are recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.

Internal Control Over Financial Reporting

During the most recent fiscal quarter, there have been no changes in our internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II — OTHER INFORMATION

ITEM 1. 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, 123rd Judicial District, David Hudson, Jr., et al v. Basic Energy Services Company, Cause No. 2004-A-137. The complaint alleged that our operation of a saltwater disposal well has contaminated both the groundwater and the soil in the surrounding area. The relief requested in the complaint was monetary damages, injunctive relief, environmental remediation and a court order requiring us to provide drinking water to the community. This matter was settled in April 2006 for an immaterial amount.

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

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

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

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

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

Recent Sales of Unregistered Securities

None during the three months ended March 31, 2006.

Purchases of Equity Securities by the Issuer and Affiliated Purchasers

The following table summarizes stock repurchase activity for the three months ended March 31, 2006:


Issuer Purchases of Equity Securities
	Total		Average				Maximum number of
	number of		price		Total number of shares		shares that may yet be
	shares		paid per		purchased as part of		purchased under the
Period	purchased		share		publicly announced plan		plan
January 1 — January 31.		—		—		—		—
February 1 — February 28 (1)		78,656	$	24.94		78,656		—
March 1 — March 31 (2)		68,118	$	27.18		—		—
Total		146,774	$	25.98		78,656		—


(1)		Prior to our initial public offering, we entered into Share Tender and Repurchase Agreements with ten of our officers in which we agreed to repurchase, and nine of the officers agreed to sell, shares of our common stock at the initial public offering price, less underwriting discounts and commissions, on the closing date of our initial public offering. These shares were repurchased to provide such officers the cash amounts necessary to pay certain tax liabilities associated with the vesting of restricted shares owned by them. Under the Share Tender and Repurchase Agreements, we also agreed to repurchase, and nine of the officers irrevocably agreed to sell, an aggregate of 78,656 shares of our common stock on February 24, 2006 at the closing price per share of common stock on that date. These shares were also purchased to provide such officers the cash amounts necessary to pay certain tax liabilities associated with the vesting of restricted shares owned by them. The Share Tender and Repurchase Agreements expired upon the consummation of the February 24, 2006 repurchase.

(2)		Represents shares surrendered by James J. Carter to us on March 21, 2006 in connection with his announced retirement and exercise of all of his vested options in a “cashless” exercise approved by our Compensation Committee in accordance with our 2003 Incentive Plan.

ITEM 6. EXHIBITS


Exhibit
No.		Description
3.1*		Amended and Restated Certificate of Incorporation of the Basic Energy Services, Inc. (the “Company”), dated September 22, 2005. (Incorporated by reference to Exhibit 3.1 of the Company’s Registration Statement on Form S-1 (SEC File No. 333-127517), filed on September 28, 2005)

3.2*		Amended and Restated Bylaws of the Company, dated December 14, 2005. (Incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K (SEC File No. 001-32693), filed on December 14, 2005)

4.1*		Specimen Stock Certificate representing common stock of the Company. (Incorporated by reference to Exhibit 3.1 of the Company’s Registration Statement on Form S-1 (SEC File No. 333-127517), filed on November 4, 2005)

4.2*		Indenture dated April 12, 2006, among Basic Energy Services, Inc., the guarantors party thereto, and The Bank of New York Trust Company, N.A., as trustee. (Incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K (SEC File No. 001-32693), filed on April 13, 2006)

4.3*		Form of 7.125% Senior Note due 2016. (Incorporated by reference to Exhibit 4.2 of the Company’s Current Report on Form 8-K (SEC File No. 001-32693), filed on April 13, 2006)

10.1*		Asset Purchase Agreement dated as of February 21, 2006 among Basic Energy Services, LP, Basic Energy Services GP, LLC, G&L Tool, Ltd., DLH Management, LLC and LJH, Ltd. (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K (SEC File No. 001-32693), filed on March 2, 2006)

10.2*		Contingent Earn Out Agreement dated as of February 28, 2006 among Basic Energy Services, LP and G&L Tool, Ltd. (Incorporated by reference to Exhibit 10.2 of the Company’s Current Report on Form 8-K (SEC File No. 001-32693), filed on March 2, 2006)

10.3*		Amendment No. 1 to Third Amended and Restated Credit Agreement, dated March 28, 2006, by and among the Company, the subsidiary guarantors party thereto, and UBS Loan Finance LLC, Bank of America, N.A., Hibernia National Bank, BNP Paribas, UBS AG, Stamford Branch, as administrative agent, and the lenders party thereto. (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K (SEC File No. 001-32693), filed on April 3, 2006)

10.4*		Purchase Agreement dated April 7, 2006, among the Company, the guarantors party thereto and the initial purchasers party thereto. (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K (SEC File No. 001-32693), filed on April 13, 2006)

10.5*		Registration Rights Agreement dated April 12, 2006, among the Company, the guarantors party thereto and the initial purchasers party thereto. (Incorporated by reference to Exhibit 10.2 of the Company’s Current Report on Form 8-K (SEC File No. 001-32693), filed on April 13, 2006)

10.6*		Summary of 2006 salaries and other compensation for named executive officers and certain employees (Incorporated by reference to Item 1.01 of the Company’s Form 8-K filed on March 8, 2006).

10.7†		Form of Nonqualified Stock Option Agreement (Director form effective March 2006)

10.8†		Form of Nonqualified Stock Option Agreement (Employee form effective March 2006)

31.1		Certification by Chief Executive Officer required by Rule 13a-14(a) and 15d-14(a) under the Exchange Act

31.2		Certification by Chief Financial Officer required by Rule 13a-14(a) and 15d-14(a) under the Exchange Act

32.1		Certification by Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

32.2		Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002


*		Incorporated by reference

†		Management contract or compensatory plan or arrangement

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.


		BASIC ENERGY SERVICES, INC.

		By:		/s/ Kenneth V. Huseman

		Name:		Kenneth V. Huseman
		Title:		President, Chief Executive
				Officer and Director
				(Principal Executive Officer)

		By:		/s/ Alan Krenek

		Name:		Alan Krenek
		Title:		Senior Vice President, Chief Financial
				Officer and Treasurer
				(Principal Financial Officer and
				Principal Accounting Officer)

		Date: May 12, 2006

Exhibit Index


Exhibit
No.		Description
3.1*		Amended and Restated Certificate of Incorporation of the Basic Energy Services, Inc. (the “Company”), dated September 22, 2005. (Incorporated by reference to Exhibit 3.1 of the Company’s Registration Statement on Form S-1 (SEC File No. 333-127517), filed on September 28, 2005)

3.2*		Amended and Restated Bylaws of the Company, dated December 14, 2005. (Incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K (SEC File No. 001-32693), filed on December 14, 2005)

4.1*		Specimen Stock Certificate representing common stock of the Company. (Incorporated by reference to Exhibit 3.1 of the Company’s Registration Statement on Form S-1 (SEC File No. 333-127517), filed on November 4, 2005)

4.2*		Indenture dated April 12, 2006, among Basic Energy Services, Inc., the guarantors party thereto, and The Bank of New York Trust Company, N.A., as trustee. (Incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K (SEC File No. 001-32693), filed on April 13, 2006)

4.3*		Form of 7.125% Senior Note due 2016. (Incorporated by reference to Exhibit 4.2 of the Company’s Current Report on Form 8-K (SEC File No. 001-32693), filed on April 13, 2006)

10.1*		Asset Purchase Agreement dated as of February 21, 2006 among Basic Energy Services, LP, Basic Energy Services GP, LLC, G&L Tool, Ltd., DLH Management, LLC and LJH, Ltd. (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K (SEC File No. 001-32693), filed on March 2, 2006)

10.2*		Contingent Earn Out Agreement dated as of February 28, 2006 among Basic Energy Services, LP and G&L Tool, Ltd. (Incorporated by reference to Exhibit 10.2 of the Company’s Current Report on Form 8-K (SEC File No. 001-32693), filed on March 2, 2006)

10.3*		Amendment No. 1 to Third Amended and Restated Credit Agreement, dated March 28, 2006, by and among the Company, the subsidiary guarantors party thereto, and UBS Loan Finance LLC, Bank of America, N.A., Hibernia National Bank, BNP Paribas, UBS AG, Stamford Branch, as administrative agent, and the lenders party thereto. (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K (SEC File No. 001-32693), filed on April 3, 2006)

10.4*		Purchase Agreement dated April 7, 2006, among the Company, the guarantors party thereto and the initial purchasers party thereto. (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K (SEC File No. 001-32693), filed on April 13, 2006)

10.5*		Registration Rights Agreement dated April 12, 2006, among the Company, the guarantors party thereto and the initial purchasers party thereto. (Incorporated by reference to Exhibit 10.2 of the Company’s Current Report on Form 8-K (SEC File No. 001-32693), filed on April 13, 2006)

10.6*		Summary of 2006 salaries and other compensation for named executive officers and certain employees (Incorporated by reference to Item 1.01 of the Company’s Form 8-K filed on March 8, 2006)

10.7†		Form of Nonqualified Stock Option Agreement (Director form effective March 2006)

10.8†		Form of Nonqualified Stock Option Agreement (Employee form effective March 2006)

31.1		Certification by Chief Executive Officer required by Rule 13a-14(a) and 15d-14(a) under the Exchange Act

31.2		Certification by Chief Financial Officer required by Rule 13a-14(a) and 15d-14(a) under the Exchange Act

32.1		Certification by Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

32.2		Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002


*		Incorporated by reference

†		Management contract or compensatory plan or arrangement