Basic Energy Services (BASWQ) 10-Q 2008 Q3 Quarterly report

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 September 30, 2008

OR

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 no. 001-32693

Basic Energy Services, Inc.

(Exact name of registrant as specified in its charter)

Delaware	54-2091194
(State or other jurisdiction of	(I.R.S. Employer
incorporation or organization)	Identification No.)
500 W. Illinois, Suite 100
Midland, Texas	79701
(Address of principal executive offices)	(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. Yesþ Noo

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

Large accelerated filero  Accelerated filerþ  Non-accelerated filer  o
(Do not check if a smaller reporting company) Smaller reporting companyo 

     Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yeso Noþ

     41,493,768 shares of the registrant’s Common Stock were outstanding as of October 31, 2008.

BASIC ENERGY SERVICES, INC.

Index to Form 10-Q

Part I. FINANCIAL INFORMATION	4
Item 1. Financial Statements	4
Consolidated Balance Sheets as of September 30, 2008 and December 31, 2007	4
Consolidated Statements of Operations and Comprehensive Income for the three months and nine months ended September 30, 2008 and 2007	5
Consolidated Statements of Stockholders’ Equity for the nine months ended September 30, 2008	6
Consolidated Statements of Cash Flows for the nine months ended September 30, 2008 and 2007	7
Notes to the Consolidated Financial Statements	8
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	26
Management’s Overview	26
Segment Overview	28
Operating Cost Overview	31
Critical Accounting Policies and Estimates	31
Results of Operations	33
Liquidity and Capital Resources	35
Other Matters	39
Item 3. Quantitative and Qualitative Disclosures About Market Risk	40
Item 4. Controls and Procedures	41
Part II. OTHER INFORMATION	41
Item 1. Legal Proceedings	41
Item 1A. Risk Factors	41
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	42
Item 4. Submission of Matters to a Vote of Security Holders	42
Item 6. Exhibits	44
Signatures	45
EX-31.1
EX-31.2
EX-32.1
EX-32.2

2

CAUTIONARY STATEMENT
REGARDING FORWARD-LOOKING STATEMENTS

     This quarterly 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 quarterly 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 quarterly report are forward looking-statements. Although we believe that the forward-looking statements contained in this quarterly report are based upon reasonable assumptions, the forward-looking events and circumstances discussed in this quarterly 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 quarterly 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.

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

3

PART I — FINANCIAL INFORMATION

ITEM 1.FINANCIAL STATEMENTS

Basic Energy Services, Inc.

Consolidated Balance Sheets

(in thousands, except share data)

	September 30,			December 31,
	2008			2007
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	80,861		$	91,941
Trade accounts receivable, net of allowance of $6,048 and $6,090, respectively		186,654			138,384
Accounts receivable — related parties		133			91
Income tax receivable		2,340			1,130
Inventories		11,551			11,034
Prepaid expenses		4,430			6,999
Other current assets		4,476			6,353
Deferred tax assets		11,269			10,593
Total current assets		301,714			266,525
Property and equipment, net		709,059			636,924
Deferred debt costs, net of amortization		5,378			6,100
Goodwill		253,492			204,963
Other intangible assets, net of amortization		38,948			26,975
Other assets		2,251			2,122
	$	1,310,842		$	1,143,609
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	23,545		$	22,146
Accrued expenses		66,522			51,003
Current portion of long-term debt		22,991			17,413
Other current liabilities		550			1,474
Total current liabilities		113,608			92,036
Long-term debt		449,404			406,306
Deferred tax liabilities		144,012			114,604
Other long-term liabilities		5,078			5,842
Commitments and contingencies
Stockholders’ equity:
Preferred stock; $.01 par value; 5,000,000 shares authorized; none designated at September 30, 2008 and December 31, 2007, respectively		—			—
Common stock; $.01 par value; 80,000,000 shares authorized; 41,734,485 issued; 41,721,670 shares outstanding at September 30, 2008 and 40,925,530 issued; 40,896,217 shares outstanding at December 31, 2007, respectively		417			409
Additional paid-in capital		325,110			314,705
Retained earnings		273,243			209,707
Treasury stock, at cost, 12,815 and 29,313 shares, respectively		(30	)		—
Total stockholders’ equity		598,740			524,821
	$	1,310,842		$	1,143,609

See accompanying notes to consolidated financial statements.

4

Basic Energy Services, Inc.

Consolidated Statements of Operations and Comprehensive Income

(in thousands, except per share amounts)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2008			2007			2008			2007
	(Unaudited)						(Unaudited)
Revenues:
Well servicing	$	97,382		$	87,890		$	266,919		$	260,670
Fluid services		82,660			63,654			226,640			191,027
Completion and Remedial Services		85,541			66,304			233,578			176,177
Contract drilling		11,992			11,384			31,832			23,544
Total revenues		277,575			229,232			758,969			651,418
Expenses:
Well servicing		61,047			52,763			164,806			154,941
Fluid services		53,028			40,902			148,015			121,383
Completion and Remedial Services		46,798			34,731			125,236			91,240
Contract drilling		7,722			6,556			22,311			15,554
General and administrative, including stock-based compensation of $1,159 and $1,073 in the three months ended September 30, 2008 and 2007, and $3,423 and $3,228 in the nine months ended September 30, 2008 and 2007, respectively		30,552			25,472			83,212			73,713
Depreciation and amortization		29,271			23,582			86,035			66,814
(Gain) loss on disposal of assets		376			58			(208	)		233
Total expenses		228,794			184,064			629,407			523,878
Operating income		48,781			45,168			129,562			127,540
Other income (expense):
Interest expense		(6,315	)		(7,375	)		(20,117	)		(20,159	)
Interest income		654			830			1,824			1,713
Loss on early extinguishment of debt		—			—			—			(230	)
Other income (expense)		(1,273	)		23			(7,708	)		124
Income from continuing operations before income taxes		41,847			38,646			103,561			108,988
Income tax expense		(15,905	)		(14,220	)		(39,253	)		(40,797	)
Net income	$	25,942		$	24,426		$	64,308		$	68,191
Earnings per share of common stock:
Basic	$	0.63		$	0.60		$	1.58		$	1.71
Diluted	$	0.62		$	0.59		$	1.54		$	1.66

See accompanying notes to consolidated financial statements.

5

Basic Energy Services, Inc.

Consolidated Statements of Stockholders’ Equity

(in thousands, except share data)

					Additional									Total
	Common Stock				Paid-In			Treasury			Retained			Stockholders’
	Shares		Amount		Capital			Stock			Earnings			Equity
Balance — December 31, 2007		40,925,530	$	409	$	314,705		$	—		$	209,707		$	524,821
Issuances of restricted stock		361,700		4		(4	)		—			—			—
Amortization of share based compensation		—		—		3,339			—			—			3,339
Treasury stock issued as compensation to Chairman of the Board		—		—		—			89			(4	)		85
Purchase of treasury stock		—		—		—			(1,179	)		—			(1,179	)
Exercise of stock options		447,255		4		7,070			1,060			(768	)		7,366
Net income		—		—		—			—			64,308			64,308
Balance -September 30, 2008 (unaudited)		41,734,485	$	417	$	325,110		$	(30	)	$	273,243		$	598,740

See accompanying notes to consolidated financial statements.

6

Basic Energy Services, Inc.

Consolidated Statements of Cash Flows

(in thousands)

	Nine Months Ended September 30,
	2008			2007
	(Unaudited)
Cash flows from operating activities:
Net income	$	64,308		$	68,191
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		86,035			66,814
Accretion on asset retirement obligation		96			85
Change in allowance for doubtful accounts		(42	)		2,261
Amortization of deferred financing costs		722			717
Non-cash compensation		3,423			3,228
Loss on early extinguishment of debt		—			230
(Gain) loss on disposal of assets		(208	)		233
Deferred income taxes		19,080			11,551
Changes in operating assets and liabilities, net of acquisitions:
Accounts receivable		(46,330	)		(8,777	)
Inventories		(173	)		(657	)
Prepaid expenses and other current assets		6,653			4,497
Other assets		(151	)		(768	)
Accounts payable		1,399			(2,450	)
Excess tax benefits from exercise of employee stock options		(4,848	)		(2,164	)
Income tax payable		2,154			(12,349	)
Other liabilities		(3,545	)		(901	)
Accrued expenses		14,894			14,214
Net cash provided by operating activities		143,467			143,955
Cash flows from investing activities:
Purchase of property and equipment		(68,868	)		(82,113	)
Proceeds from sale of assets		8,055			3,082
Payments for other long-term assets		(2,118	)		(4,973	)
Payments for businesses, net of cash acquired		(110,818	)		(194,430	)
Net cash used in investing activities		(173,749	)		(278,434	)
Cash flows from financing activities:
Proceeds from debt		30,000			150,000
Payments of debt		(16,987	)		(11,461	)
Purchase of treasury stock		(1,179	)		(462	)
Excess tax benefits from exercise of employee stock options		4,848			2,164
Tax withholding from exercise of stock options		(4,063	)		(1,285	)
Exercise of employee stock options		6,583			2,253
Deferred loan costs and other financing activities		—			(756	)
Net cash provided by (used in) financing activities		19,202			140,453
Net increase (decrease) in cash and equivalents		(11,080	)		5,974
Cash and cash equivalents — beginning of period		91,941			51,365
Cash and cash equivalents — end of period	$	80,861		$	57,339

See accompanying notes to consolidated financial statements.

7

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements

September 30, 2008 (unaudited)

1. Basis of Presentation and Nature of Operations

Basis of Presentation

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

Nature of Operations

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

2. Summary of Significant Accounting Policies

Principles of Consolidation

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

Estimates and Uncertainties

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

• Depreciation and amortization of property and equipment and intangible assets

• Impairment of property and equipment, goodwill and intangible assets

• Allowance for doubtful accounts

• Litigation and self-insured risk reserves

• Fair value of assets acquired and liabilities assumed

• Stock-based compensation

• Income taxes

• Asset retirement obligation

8

Revenue Recognition

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

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

     Completion and Remedial Services— Completion and remedial services consists primarily of pressure pumping services, focused on cementing, acidizing and fracturing, and rental and fishing tools. Basic recognizes revenue when services are performed, collection of the relevant receivables is probable, persuasive evidence of an arrangement exists and the price is fixed or determinable. Basic prices completion and remedial services by the hour, day, or project depending on the type of service performed. When Basic provides multiple services to a customer, revenue is allocated to the services performed based on the fair values of the services.

     Contract Drilling— Contract drilling consists primarily of drilling wells to a specified depth using shallow and medium depth rigs. Basic recognizes revenues based on either a “daywork” contract, in which an agreed upon rate per day is charged to the customer, or a “footage” contract, in which an agreed upon rate is charged per the number of feet drilled.

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

Inventories

     For Rental and Fishing Tools, inventories consisting mainly of grapples, controls, and drill bits are stated at the lower of cost or market, which cost being determined on the average cost method. Other inventories, consisting mainly of rig components, repair parts, drilling and completion materials and gravel, are held for use in the operations of Basic and are stated at the lower of cost or market, with cost being determined on the first-in, first-out (“FIFO”) method.

Impairments

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

     Goodwill is tested annually for impairment, and is 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 nine months ended September 30, 2008 and 2007.

9

Deferred Debt Costs

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

     Deferred debt costs were approximately $5.4 million net of accumulated amortization of $2.2 million and $6.1 million net of accumulated amortization of $1.5 million at September 30, 2008 and December 31, 2007, respectively. Amortization of deferred debt costs totaled approximately $240,000 and $245,000 for the three months ended September 30, 2008 and 2007, respectively. For the nine months ended September 30, 2008 and 2007, amortization of deferred debt costs totaled approximately $723,000 and $717,000, respectively.

Goodwill and Other Intangible Assets

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

     Basic has identified its reporting units to be well servicing, fluid services, completion and remedial services and contract drilling. The goodwill allocated to such reporting units as of September 30, 2008 is $34.6 million, $63.6 million, $130.6 million and $24.7 million, respectively. The change in the carrying amount of goodwill for the nine months ended September 30, 2008 of $48.5 million relates to goodwill from acquisitions and payments pursuant to contingent earn-out agreements, with approximately $7.9 million, $20.3 million, $19.0 million, and $1.3 million of goodwill additions relating to well servicing, fluid services, completion and remedial, and contract drilling, respectively.

     Intangible assets subject to amortization under SFAS No. 142 consist of customer relationships and non-compete agreements. The gross carrying amount of customer relationships subject to amortization was $37.5 million and $23.8 million as of September 30, 2008 and December 31, 2007, respectively. The gross carrying amount of non-compete agreements subject to amortization totaled approximately $5.5 million and $5.2 million at September 30, 2008 and December 31, 2007, respectively. Accumulated amortization related to these intangible assets totaled approximately $4.0 million and $2.1 million at September 30, 2008 and December 31, 2007, respectively. Amortization expense for the three months ended September 30, 2008 and 2007 was approximately $695,000 and $209,000, respectively. For the nine months ended September 30, 2008 and 2007, amortization expense totaled approximately $2.0 million and $546,000, respectively. Other intangibles net of accumulated amortization allocated to reporting units as of September 30, 2008 is $214,000, $10.5 million, $22.2 million and $6.0 million for well servicing, fluid services, completion and remedial services and contract drilling, respectively.

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

Stock-Based Compensation

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

10

Income Taxes

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

     Interest charges are recorded in interest expense and penalties are recorded in income tax expense.

Concentrations of Credit Risk

     Financial instruments, which potentially subject Basic to concentration of credit risk, consist primarily of temporary cash investments and trade receivables. Basic restricts investment of temporary cash investments to financial institutions with high credit standing. Basic’s customer base consists primarily of multi-national and independent oil and natural gas producers. It performs ongoing credit evaluations of its customers but generally does not require collateral on its trade receivables. Credit risk is considered by management to be limited due to the large number of customers comprising its customer base. Basic maintains an allowance for potential credit losses on its trade receivables, and such losses have been within management’s expectations.

     Basic did not have any one customer which represented 10% or more of consolidated revenue during the nine months ended September 30, 2008 or 2007.

Asset Retirement Obligations

     As of January 1, 2003, Basic adopted Statement of Financial Accounting Standards No. 143,“Accounting for Asset Retirement Obligation”(“SFAS No. 143”). SFAS No. 143 requires Basic to record the fair value of an asset retirement obligation as a liability in the period in which it incurs a legal obligation associated with the retirement of tangible long-lived assets and capitalize an equal amount as a cost of the asset depreciating it over the life of the asset. Subsequent to the initial measurement of the asset retirement obligation, the obligation is adjusted at the end of each quarter to reflect the passage of time, changes in the estimated future cash flows underlying the obligation, acquisition or construction of assets, and settlements of obligations.

     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 nine months ended September 30, 2008 (in thousands):

Balance, December 31, 2007	$	1,552
Additional asset retirement obligations recognized through acquisitions		143
Accretion expense		96
Balance, September 30, 2008	$	1,791

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.

11

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

     In February 2007, the FASB issuedSFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities (SFAS 159), which became effective for the company on January 1, 2008. This standard permits companies to choose to measure many financial instruments and certain other items at fair value and report unrealized gains and losses in earnings. Such accounting is optional and is generally to be applied instrument by instrument. The adoption of this standard has not had any material effect on the results of operations or consolidated financial position.

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

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

     In March 2008, the FASB issued SFAS No. 161,Disclosures about Derivative Instruments and Hedging Activities(SFAS 161), which becomes effective for the Company on January 1, 2009. This standard improves financial reporting for derivative instruments and hedging activities by requiring enhanced disclosures to expand on these instruments’ effects on the company’s financial position, financial performance and cash flows. The Company does not anticipate that this pronouncement will have a material impact on its results of operations or consolidated financial position.

     In May 2008, the FASB issued SFAS No. 162,The Hierarchy of Generally Accepted Accounting Principles(SFAS 162), which becomes effective for the Company 60 days following the SEC’s approval of the Public Company Accounting Oversight Board amendments to AU Section 411,The Meaning of Present Fairly in Conformity With General Accepted Accounting Principles. This standard identifies the sources of accounting principles and the framework for selecting the principles used in the preparation of financial statements that are presented in conformity with generally accepted accounting principles (GAAP). The Company does not anticipate that this pronouncement will have a material impact on its results of operations or consolidated financial position.

     In June 2008, the FASB issued FASB Staff Position EITF 03-6-1“Determining Whether Instruments Granted in Share-Based Payment Transactions are Participating Securities”(“FSP EITF 03-6-1”). FSP EITF 03-6-1 addresses whether instruments granted in share-based payment transactions are participating securities prior to vesting and, therefore, need to be included in the earnings

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allocation in computing earnings per share (“EPS”) under the two-class method described in paragraphs 60 and 61 of SFAS No. 128, “Earnings Per Share”. FSP EITF 03-6-1 is effective for financial statements issued for fiscal years and interim periods beginning after December 15, 2008 and requires retrospective adjustment for all comparable prior periods presented. The Company does not anticipate that the adoption of FSP EITF 03-6-1 will have a material impact on its EPS disclosures.

3. Acquisitions

     In 2008 and 2007, 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
	Closing Date	cash acquired)
Parker Drilling Offshore USA, LLC	January 3, 2007	$	20,594
Davis Tool Company, Inc.	January 17, 2007		4,164
JetStar Consolidated Holdings, Inc. (“JetStar”)	March 6, 2007		86,316
Sledge Drilling Holding Corp. (“Sledge”)	April 2, 2007		50,632
Eagle Frac Tank Rentals, LP	May 30, 2007		3,813
Wildhorse Services, Inc.	June 1, 2007		17,319
Bilco Machine, Inc.	June 21, 2007		600
Steve Carter Inc. and Hughes Services Inc.	September 26, 2007		19,040
Total 2007		$	202,478
Xterra Fishing and Rental Tools Co.	January 28, 2008	$	21,109
Lackey Construction, LLC	January 30, 2008		4,328
B&S Disposal, LLC and B&S Equipment, Ltd	April 30, 2008		7,059
Triple N Services, Inc.	May 27, 2008		17,314
Azurite Services Company, Inc., Azurite Leasing Company, LLC and Freestone Disposal, L.P. (collectively, “Azurite”)	September 26, 2008		60,035
Total 2008		$	109,845

     The operations of each of the acquisitions listed above are included in Basic’s statement of operations as of each respective closing date. The acquisitions of JetStar and Sledge in 2007 and Azurite in 2008 have been deemed material and are discussed below in further detail.

Contingent Earn-out Arrangements and Purchase Price Allocations

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

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JetStar

     On March 6, 2007, Basic acquired all of the capital stock of JetStar Consolidated Holdings, Inc. (“JetStar”). The results of JetStar’s operations have been included in the financial statements since that date. The aggregate purchase price was approximately $127.3 million, including $86.3 million in cash which included the retirement of JetStar’s outstanding debt. Basic issued 1,794,759 shares of common stock, at a fair value of $22.86 per share, for a total fair value of approximately $41 million. The value of the 1,794,759 shares issued was determined based on the average market price of Basic’s common shares over the 2-day period before and after the date the number of shares were determined. This acquisition allowed us to enter into the Kansas market and increased our presence in North Texas. JetStar operates in Basic’s completion and remedial segment. The following table summarizes the final estimated fair value of the assets acquired and liabilities assumed at the date of acquisition for JetStar (in thousands):

Current Assets	$	12,547
Property and Equipment		58,785
Amortizable Intangible Assets (1)		17,857
Goodwill (2)		61,720
Total Assets Acquired	$	150,909
Current Liabilities	$	(4,581	)
Deferred Income Taxes		(18,649	)
Current and Long Term Debt (3)		(37,563	)
Total Liabilities Assumed	$	(60,793	)
Net Assets Acquired	$	90,116

(1)	Consists of customer relationship of $17,543, amortizable over 15 years, and non-compete agreements of $314, amortizable over five years.
(2)	Approximately $25,955 is expected to be deductible for tax purposes.
(3)	Total balance was paid by Basic on the closing date.

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     Sledge

     On April 2, 2007, Basic acquired all of the capital stock of Sledge Drilling Holding Corp. (“Sledge”). The results of Sledge’s operations have been included in the financial statements since that date. The aggregate purchase price was approximately $60.8 million, including $50.6 million in cash which included the retirement of Sledge’s outstanding debt. Basic issued 430,191 shares of common stock at a fair value of $23.63 per share for a total fair value of approximately $10.2 million. The value of the 430,191 shares issued was determined based on the average market price of Basic’s common shares over the 2-day period before and after the date the number of shares were determined. This acquisition allowed Basic to expand its drilling operations in the Permian Basin. The following table summarizes the final estimated fair value of the assets acquired and liabilities assumed at the date of acquisition for Sledge (in thousands):

Current Assets	$	6,029
Property and Equipment		30,638
Intangible Assets (1)		6,365
Goodwill (2)		24,665
Total Assets Acquired	$	67,697
Current Liabilities	$	(587	)
Deferred Income Taxes		(5,169	)
Current and Long Term Debt (3)		(19,093	)
Total Liabilities Assumed	$	(24,849	)
Net Assets Acquired	$	42,848

(1)	Consists of customer relationship of $6,269, amortizable over 15 years, and non-compete agreement of $96, amortizable over five years.
(2)	None of which is expected to be deductible for tax purposes.
(3)	Total balance was paid by Basic on the closing date.

     Azurite

     On September 26, 2008, Basic acquired substantially all of the assets of Azurite Services Company, Inc., Azurite Leasing Company, LLC, and Freestone Disposal, L.P. (collectively, “Azurite”) for $60.0 million in cash. This acquisition will operate in our fluid services line of business and expand our operations in the east Texas markets. The following table summarizes the preliminary estimated fair value of the assets acquired and liabilities assumed at the date of acquisition for Azurite (in thousands):

Property and Equipment	$	34,389
Intangible Assets (1)		7,230
Goodwill (2)		18,416
Total Assets Acquired	$	60,035

(1)	Consists of customer relationship of $7,200, amortizable over 15 years, and non-compete agreements of $30, amortizable over five years.
(2)	All of which is expected to be deductible for tax purposes.

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     The following unaudited proforma results of operations have been prepared as though the JetStar, Sledge and Azurite acquisitions had been completed on January 1, 2007. Pro forma amounts are based on the purchase price allocations of the significant acquisitions and are not necessarily indicative of the results that may be reported in the future (in thousands, except per share data).

	Nine Months Ended September 30,
	2008		2007
Revenues	$	798,656	$	700,549
Net income	$	70,100	$	74,859
Earnings per common share — basic	$	1.72	$	1.85
Earnings per common share — diluted	$	1.68	$	1.80

     Basic does not believe the proforma effect of the remainder of the acquisitions completed in 2008 or 2007 are 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):

	September 30,		December 31,
	2008		2007
Land	$	4,905	$	3,475
Buildings and improvements		28,860		21,655
Well service units and equipment		367,151		328,468
Fluid services equipment		123,944		91,830
Brine and fresh water stations		9,852		8,964
Frac/test tanks		116,799		85,649
Pressure pumping equipment		156,656		132,746
Construction equipment		22,261		28,798
Contract drilling		59,842		59,231
Disposal facilities		41,032		27,790
Vehicles		39,412		36,440
Rental equipment		27,690		33,381
Aircraft		4,119		4,119
Other		19,616		15,858
		1,022,139		878,404
Less accumulated depreciation and amortization		313,080		241,480
Property and equipment, net	$	709,059	$	636,924

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     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):

	September 30,		December 31,
	2008		2007
Light vehicles	$	29,108	$	25,768
Well service units and equipment		1,194		1,016
Fluid services equipment		48,654		34,668
Pressure pumping equipment		17,271		4,540
Construction equipment		3,679		4,440
Software		8,562		6,308
Other		705		—
		109,173		76,740
Less accumulated amortization		33,134		22,660
	$	76,039	$	54,080

     Amortization of assets held under capital leases of approximately $3.8 million and $2.3 million for the three months ended September 30, 2008 and 2007 and $10.5 million and $6.1 million for the nine months ended September 30, 2008 and 2007, 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):

	September 30,		December 31,
	2008		2007
Credit Facilities:
Revolver	$	180,000	$	150,000
7.125% Senior Notes		225,000		225,000
Capital leases and other notes		67,395		48,719
		472,395		423,719
Less current portion		22,991		17,413
	$	449,404	$	406,306

Senior Notes

     On April 12, 2006, Basic issued $225.0 million of 7.125% Senior Notes due April 2016 in a private placement. Proceeds from the sale of the Senior Notes were used to retire the outstanding balance on the $90.0 million Term B Loan and to pay down approximately $96.0 million under the revolving credit facility, which amounts may be reborrowed to fund future acquisitions or for general corporate purposes. Interest payments on the Senior Notes are due semi-annually, on April 15 and October 15, which began on October 15, 2006. The Senior Notes are unsecured. Under the terms of the sale of the Senior Notes, Basic was required to take appropriate steps to offer to exchange other Senior Notes with the same terms that have been registered with the Securities and Exchange Commission for the private placement Senior Notes. Basic completed the exchange offer for all of the Senior Notes on October 16, 2006.

     The Senior Notes are redeemable at the option of Basic on or after April 15, 2011 at the specified redemption price as described in the Indenture. Prior to April 15, 2011, Basic may redeem, in whole or in part, at a redemption price equal to 100% of the principal amount of the Senior Notes redeemed plus the Applicable Premium as defined in the Indenture. Prior to April 15, 2009, Basic may redeem up to 35% of the Senior Notes with the proceeds of certain equity offerings at a redemption price equal to 107.125% of the principal amount of the 7.125% Senior Notes, plus accrued and unpaid interest to the date of redemption. This redemption must occur less than 90 days after the date of the closing of any such equity offering.

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     Following a change of control, as defined in the Indenture, Basic will be required to make an offer to repurchase all or any portion of the 7.125% Senior Notes at a purchase price of 101% of the principal amount, plus accrued and unpaid interest to the date of repurchase.

     Pursuant to the Indenture, Basic is subject to covenants that limit the ability of Basic and its restricted subsidiaries to, among other things: incur additional indebtedness, pay dividends or repurchase or redeem capital stock, make certain investments, incur liens, enter into certain types of transactions with affiliates, limit dividends or other payments by restricted subsidiaries, and sell assets or consolidate or merge with or into other companies. These limitations are subject to a number of important qualifications and exceptions set forth in the Indenture. Basic was in compliance with the restrictive covenants at September 30, 2008.

     As part of the issuance of the above-mentioned Senior Notes, Basic incurred debt issuance costs of approximately $4.6 million, which are being amortized to interest expense using the effective interest method over the term of the Senior Notes.

     The Senior Notes are jointly and severally guaranteed by Basic and all of its restricted subsidiaries. Basic Energy Services, Inc., the ultimate parent company, does not have any independent operating assets or operations. Subsidiaries other than the restricted subsidiaries that are guarantors are minor.

2007 Credit Facility

     On February 6, 2007, Basic entered into a $225 million Fourth Amended and Restated Credit Agreement with a syndicate of lenders (the “2007 Credit Facility”), which refinanced all of the existing credit facilities. Under the 2007 Credit Facility, Basic Energy Services, Inc. is the sole borrower and each of our subsidiaries is a subsidiary guarantor. The 2007 Credit Facility provides for a $225 million revolving line of credit (“Revolver”). The 2007 Credit Facility includes provisions allowing us to request an increase in commitments of up to $100.0 million aggregate principal amount at any time. Additionally, the 2007 Credit Facility permits us to make greater expenditures for acquisitions, capital expenditures and capital leases and to incur greater purchase money obligations, acquisition indebtedness and general unsecured indebtedness. The commitment under the Revolver provides for (1) the borrowing of funds, (2) the issuance of up to $30 million of letters of credit and (3) $2.5 million of swing-line loans. All of the outstanding amounts under the Revolver are due and payable on December 15, 2010. The 2007 Credit Facility is secured by substantially all of our tangible and intangible assets. Basic incurred approximately $0.7 million in debt issuance costs in connection with the 2007 Credit Facility.

     At Basic’s option, borrowings under the Revolver 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 a margin ranging from 0.25% to 0.5% or (2) an “Adjusted LIBOR Rate” (equal to (a) the London Interbank Offered Rate (the “LIBOR rate”) as determined by the Administrative Agent in effect for such interest period divided by (b) one minus the Statutory Reserves, if any, for such borrowing for such interest period) plus a margin ranging from 1.25% to 1.5%. The margins vary depending on our leverage ratio. Fees on the letters of credit are due quarterly on the outstanding amount of the letters of credit at a rate ranging from 1.25% to 1.5% for participation fees and 0.125% for fronting fees. A commitment fee is due quarterly on the available borrowings under the Revolver at a rate of 0.375%.

     At September 30, 2008, Basic, under its Revolver, had outstanding $180.0 million of borrowings and $16.2 million of letters of credit and no amounts outstanding in swing-line loans. At September 30, 2008, Basic had availability under its Revolver of $28.8 million.

     Pursuant to the 2007 Credit Facility, Basic must apply proceeds from certain specified events to reduce principal outstanding borrowings under the Revolver, from (a) assets sales greater than $2.0 million individually or $7.5 million in the aggregate on an annual basis, (b) 100% of the net cash proceeds from any debt issuance, including certain permitted unsecured senior or senior subordinated debt, but excluding certain other permitted debt issuances and (c) 50% of the net cash proceeds from any equity issuance (including equity issued upon the exercise of any warrant or option).

     The 2007 Credit Facility contains various restrictive covenants and compliance requirements, which include (a) limitations on the incurrence of additional indebtedness, (b) restrictions on mergers, sales or transfer of assets without the lenders’ consent (c) limitations on dividends and distributions and (d) various financial covenants, including (1) a maximum leverage ratio of 3.25 to 1.00, and (2) a minimum interest coverage ratio of 3.00 to 1.00. At September 30, 2008, Basic was in compliance with its covenants.

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Other Debt

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

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

	Nine Months Ended September 30,
	2008		2007
Cash payments for interest	$	14,910	$	14,595
Commitment and other fees paid		155		193
Amortization of debt issuance costs		723		717
Accrued interest		4,046		4,354
Other		283		300
	$	20,117	$	20,159

Losses on Extinguishment of Debt

     In February 2007, Basic wrote off unamortized debt issuance costs of approximately $230,000, which related to the 2005 Credit Facility.

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 $375,000 and $180,000, respectively. Basic has lower deductibles per occurrence for automobile liability and general liability. Basic maintains accruals in the accompanying consolidated balance sheets related to self-insurance retentions by using third-party data and claims history.

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     At September 30, 2008 and December 31, 2007, self-insured risk accruals for medical and dental coverage totaled approximately $16.5 million and $15.1 million, respectively.

7. Stockholders’ Equity

Common Stock

     During the year ended December 31, 2007, Basic issued 169,875 shares of newly-issued common stock and 22,800 shares of treasury stock for the exercise of stock options.

     In March and April 2007, Basic issued 1,794,759 and 430,191 shares of common stock in connection with the acquisitions of JetStar Consolidated Holdings, Inc. and Sledge Drilling Holding Corp., respectively. (See note 3).

     In March 2007, Basic granted various employees 217,100 unvested shares of common stock which vest over a five year period. Also, in March 2007, Basic granted the Chairman of the Board 4,000 shares of common stock which vested immediately. In July 2007, Basic granted, a vice president, 12,000 shares of unvested shares of common stock which vest over a four-year period.

     During the first nine months of 2008, Basic received 51,720 shares of treasury stock at $22.21 per share and 1,157 shares of treasury stock at $25.77 per share, as part of net share settlements for payment of taxes upon the vesting of restricted stock. Basic also issued 447,255 shares of newly-issued common stock and 86,875 shares of treasury stock for the exercise of stock options.

     In March 2008, Basic granted various employees 361,700 unvested shares of common stock which vest over a five-year period. Also, in March 2008, Basic granted the Chairman of the Board 4,000 shares of common stock which vested immediately in lieu of annual cash director fees.

Preferred Stock

     At September 30, 2008 and December 31, 2007, Basic had 5,000,000 shares of $.01 par value preferred stock authorized, of which none is designated.

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, 2007, the board of directors granted various employees options to purchase 92,000 shares of common stock of Basic at an exercise price of $22.66 per share. All of the 92,000 options granted in 2007 vest over a five-year period and expire 10 years from the date they were granted. These option awards were granted with an exercise price equal to the market price of the Company’s stock at the date of grant.

     The fair value of each option award is estimated on the date of grant using the Black-Scholes-Merton option-pricing model that uses the subjective assumptions noted in the following table. Since the Company has only been public since December 2005, expected volatility for options granted during 2007 is a combination of the Company’s historical data and implied volatility based upon a peer group. The expected term of options granted represents the period of time that options granted are expected to be outstanding. For options granted in 2007, the Company used the simplified method to calculate the expected term. For options granted in 2007, the risk-free rate for periods within the contractual life of the options is based on the U.S. Treasury yield curve in effect at the time of grant. The estimates involve inherent uncertainties and the application of management judgment. In addition, we are required to estimate the expected forfeiture rate and only recognize expense for those options expected to vest. During the three months ended September 30, 2008 and 2007 compensation expense related to share-based arrangements was approximately$1.2 million and $1.1

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million, respectively. For compensation expense recognized during the three months ended September 30, 2008 and 2007, Basic recognized a tax benefit of approximately $441,000 and $395,000 respectively. During the nine months ended September 30, 2008 and 2007, compensation expense related to share-based arrangements was approximately $3.4 million and $3.2 million, respectively. For compensation expense recognized during the nine months ended September 30, 2008 and 2007, Basic recognized a tax benefit of approximately $1.3 million and $1.2 million, respectively.

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

	Nine Months Ended
	September 30, 2007
Risk-free interest rate		4.5	%
Expected term		6.65
Expected volatility		45.3	%
Expected dividend yield		—

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

     The following table reflects the summary of stock options outstanding at September 30, 2008 and the changes during the nine months then ended:

						Weighted
				Weighted		Average		Aggregate
	Number of			Average		Remaining		Instrinsic
	Options			Exercise		Contractual		Value
	Granted			Price		Term (Years)		(000’s)
Non-statutory stock options:
Outstanding, beginning of period		2,257,355		$	9.58
Options granted		—		$	—
Options forfeited		(38,750	)	$	16.59
Options exercised		(534,130	)	$	4.72
Options expired		(5,500	)	$	22.33
Outstanding, end of period		1,678,975		$	10.92		5.97	$	19,366
Exercisable, end of period		1,000,725		$	7.13		5.23	$	14,637
Vested or expected to vest, end of period		1,666,485		$	10.81		5.96	$	19,366

     The weighted-average grant date fair value of share options granted during the nine months ended September 30, 2007 was $11.85. The total intrinsic value of share options exercised during the nine months ended September 30, 2008 and 2007 was approximately $11.7 million and $3.6 million, respectively.

     On March 11, 2008, the Compensation Committee of our Board of Directors approved grants of performance-based stock awards to certain members of management. The performance-based awards consist of the Company achieving certain earnings per share growth targets and certain return on capital employed performance, over the performance period from January 1, 2006 through December 31, 2008 as compared to other members of a defined peer group. The number of shares to be issued will range from 0% to 150% of the target number of shares of 101,500 depending on the performance noted above. Any shares earned at the end of the performance period will then remain subject to vesting over a three-year period, with the first shares vesting March 15, 2010.

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     A summary of the status of the Company’s non-vested share grants at September 30, 2008 and changes during the nine months ended September 30, 2008 is presented in the following table:

				Weighted Average
	Number of			Grant Date Fair
Nonvested Shares	Shares			Value Per Share
Nonvested at beginning of period		378,000		$	15.74
Granted during period		451,975			20.94
Vested during period		(178,300	)		7.90
Forfeited during period		(21,500	)		21.88
Nonvested at end of period		630,175		$	21.48

     As of September 30, 2008, there was approximately $13.7 million of total unrecognized compensation related to non-vested share-based compensation arrangements granted under the Plan. That cost is expected to be recognized over a weighted-average period of 2.89 years. The total fair value of share-based awards vested during the nine months ended September 30, 2008 and 2007 was approximately $10.2 million and $10.8 million, respectively. The actual tax benefit realized for the tax deduction from vested share-based awards was $1.3 million and $1.5 million for the nine months ended September 30, 2008 and 2007, respectively.

     Cash received from share option exercises under the incentive plan was approximately $2.5 million and $983,000 for the nine months ended September 30, 2008 and 2007, respectively. The actual tax benefit realized for the tax deductions from options exercised was $4.5 million and $1.3 million for the nine months ended September 30, 2008 and 2007, respectively.

     The Company has a history of issuing treasury and newly-issued shares to satisfy share option exercises.

9. Related Party Transactions

     Basic had receivables from employees of approximately $133,000 and $91,000 as of September 30, 2008 and December 31, 2007, respectively. During 2006, Basic entered into a lease agreement with Darle Vuelta Cattle Co., LLC, an affiliate of the Chief Executive Officer, for approximately $69,000. The term of the lease is five years and will continue on a year-to-year basis unless terminated by either party.

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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 period. Diluted earnings per common share is based on the increased number of shares that would be outstanding assuming conversion of dilutive outstanding securities using the “as if converted” method. The following table sets forth the computation of basic and diluted earnings per share (in thousands, except share data):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2008		2007		2008		2007
	(Unaudited)				(Unaudited)
Numerator (both basic and diluted):
Net income	$	25,942	$	24,426	$	64,308	$	68,191
Denominator:
Denominator for basic earnings per share		40,988,436		40,515,934		40,762,759		39,843,159
Stock options		685,428		791,290		769,307		857,971
Unvested restricted stock		113,382		283,504		230,285		259,560
Denominator for diluted earnings per share		41,787,246		41,590,728		41,762,351		40,960,690
Basic earnings per common share:	$	0.63	$	0.60	$	1.58	$	1.71
Diluted earnings per common share:	$	0.62	$	0.59	$	1.54	$	1.66

11. Business Segment Information

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

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

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

     Completion and Remedial Services:This segment utilizes a fleet of pressure pumping units, air compressor packages specially configured for underbalanced drilling operations, cased-hole wireline units and an array of specialized rental equipment and fishing tools. The largest portion of this business consists of pressure pumping services focused on cementing, acidizing and fracturing services in niche markets.

     Contract Drilling:This segment utilizes shallow and medium depth rigs and associated equipment for drilling wells to a specified depth for customers on a contract basis.

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     Basic’s management evaluates the performance of its operating segments based on operating revenues and segment profits. Corporate expenses include general corporate expenses associated with managing all reportable operating segments. Corporate assets consist principally of working capital and debt financing costs.

The following table sets forth certain financial information with respect to Basic’s reportable segments (in thousands):

							Completion
	Well			Fluid			and Remedial			Contract			Corporate
	Servicing			Services			Services			Drilling			and Other		Total
Three Months Ended September 30, 2008 (Unaudited)
Operating revenues	$	97,382		$	82,660		$	85,541		$	11,992		$	—	$	277,575
Direct operating costs		(61,047	)		(53,028	)		(46,798	)		(7,722	)		—		(168,595	)
Segment profits	$	36,335		$	29,632		$	38,743		$	4,270		$	—	$	108,980
Depreciation and amortization	$	11,327		$	7,909		$	6,974		$	1,764		$	1,297	$	29,271
Capital expenditures, (excluding acquisitions)	$	9,228		$	6,442		$	5,681		$	1,437		$	1,057	$	23,845
Three Months Ended September 30, 2007 (Unaudited)
Operating revenues	$	87,890		$	63,654		$	66,304		$	11,384		$	—	$	229,232
Direct operating costs		(52,763	)		(40,902	)		(34,731	)		(6,556	)		—		(134,952	)
Segment profits	$	35,127		$	22,752		$	31,573		$	4,828		$	—	$	94,280
Depreciation and amortization	$	9,316		$	6,234		$	5,305		$	1,776		$	951	$	23,582
Capital expenditures, (excluding acquisitions)	$	11,558		$	7,735		$	6,582		$	2,204		$	1,180	$	29,259
Nine Months Ended September 30, 2008 (Unaudited)
Operating revenues	$	266,919		$	226,640		$	233,578		$	31,832		$	—	$	758,969
Direct operating costs		(164,806	)		(148,015	)		(125,236	)		(22,311	)		—		(460,368	)
Segment profits	$	102,113		$	78,625		$	108,342		$	9,521		$	—	$	298,601
Depreciation and amortization	$	33,294		$	23,245		$	20,497		$	5,185		$	3,814	$	86,035
Capital expenditures, (exluding acquisitions)	$	26,651		$	18,607		$	16,407		$	4,150		$	3,053	$	68,868
Identifiable assets	$	307,739		$	264,261		$	333,780		$	72,008		$	333,054	$	1,310,842
Nine Months Ended September 30, 2007 (Unaudited)
Operating revenues	$	260,670		$	191,027		$	176,177		$	23,544		$	—	$	651,418
Direct operating costs		(154,941	)		(121,383	)		(91,240	)		(15,554	)		—		(383,118	)
Segment profits	$	105,729		$	69,644		$	84,937		$	7,990		$	—	$	268,300
Depreciation and amortization	$	26,393		$	17,662		$	15,030		$	5,034		$	2,695	$	66,814
Capital expenditures, (excluding acquisitions)	$	32,438		$	21,706		$	18,471		$	6,186		$	3,312	$	82,113
Identifiable assets	$	282,955		$	217,754		$	284,275		$	72,644		$	271,401	$	1,129,029

     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 September 30,						Nine Months Ended September 30,
	2008			2007			2008			2007
Segment profits	$	108,980		$	94,280		$	298,601		$	268,300
General and administrative expenses		(30,552	)		(25,472	)		(83,212	)		(73,713	)
Depreciation and amortization		(29,271	)		(23,582	)		(86,035	)		(66,814	)
Gain (loss) on disposal of assets		(376	)		(58	)		208			(233	)
Operating income	$	48,781		$	45,168		$	129,562		$	127,540

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12. Supplemental Schedule of Cash Flow Information

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

	Nine Months Ended September 30,
	2008		2007
	(In thousands)
Capital leases issued for equipment	$	35,663	$	20,127
Value of Shares that may be issued	$	—	$	2,194
Contingent earnout accrual	$	435	$	1,214
Asset retirement obligation additions	$	143	$	101
Value of common stock issued in business combinations	$	—	$	51,193

     Basic paid income taxes of approximately $17.3 million and $37.8 million during the nine months ended September 30, 2008 and 2007, respectively. Basic paid interest of approximately $14.9 million and $14.6 million during the nine months ended September 30, 2008 and 2007, respectively.

13. Subsequent Events

     On October 13, 2008, Basic Energy Services, Inc. (“Basic”) announced that its Board of Directors has authorized the repurchase of up to $50.0 million of Basic’s common shares from time to time in open market or private transactions, at Basic’s discretion.

     On October 27, 2008, Basic filed a universal Shelf Registration Statement on Form S-3 with the Securities and Exchange Commission to sell from time to time up to $1 billion of securities, including common stock, preferred stock, debt securities, warrants and units.

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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, completion and remedial services and contract drilling. Our results of operations reflect the impact of our acquisition strategy as a leading consolidator in the domestic land-based well services industry. Our acquisitions have increased our breadth of service offerings at the well site and expanded our market presence. In implementing this strategy, we have purchased businesses and assets in 48 separate acquisitions from January 1, 2003 to September 30, 2008. Our weighted average number of well servicing rigs has increased from 126 in 2001 to 412 in the third quarter of 2008 and our weighted average number of fluid service trucks has increased from 156 to 683 in the same period. These acquisitions make changes in revenues, expenses and income not directly comparable between periods.

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

	Nine Months Ended September 30,
Revenues:	2008				2007
Well servicing	$	266.9	35	%	$	260.7	40	%
Fluid services		226.6	30	%		191.0	29	%
Completion and Remedial		233.6	31	%		176.2	27	%
Contract Drilling		31.8	4	%		23.5	4	%
Total revenues	$	758.9	100	%	$	651.4	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.

     Natural gas prices reached historical highs in 2006 which stimulated increased drilling activity by our customers. In 2007, natural gas prices declined as an excess supply of natural gas began to occur, mainly due to moderate U.S. weather patterns. Utilization for our services declined from 2006 levels as drilling activity flattened or declined in several of our markets and new equipment entered the marketplace balancing supply and demand for our services. However, pricing for our services improved in 2007 from 2006, mainly reflecting continued increases in labor costs, and offset a portion the effect of the lower utilization of our services on our total revenues. In the first three quarters of 2008, the utilization and pricing of our services was comparable to 2007. However, during the third quarter of 2008, oil and natural gas prices have decreased significantly. These decreases could cause fluctuations in the demand and pricing of our services in the fourth quarter of 2008 and beyond. We are also experiencing cost inflation for fuel and fuel-based supplies and services, which is creating a negative impact on segment margins. In certain cases, we are able to mitigate this impact by charging fuel surcharges to our customers, when appropriate.

     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. Recent adverse changes in capital markets have also caused a number of oil and gas producers to announce reductions in capital budgets for future periods.  Limitations on the availability of capital, or higher costs of capital, for financing expenditures may cause these and other oil and gas producers to make additional reductions to capital budgets in the future even if commodity prices remain at historically high levels.

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

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

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

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

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

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

     We 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 for each of those alternatives, which is substantially driven by the cost to acquire existing assets from a third party, the capital required to build new equipment and the point in the oil and gas commodity price cycle. Based on these factors, we make capital investment decisions that we believe will support our long-term growth strategy. While we believe our costs of integration for prior acquisitions have been reflected in our historical results of operations, integration of acquisitions may result in unforeseen operational difficulties or require a disproportionate amount of our management’s attention. 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

Selected 2007 Acquisitions

     During 2007, we made several acquisitions that complemented our existing lines of business and increased our presence in the rental tool business. These included, among others:

Parker Drilling Offshore USA, LLC

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

JetStar Consolidated Holdings, Inc.

     On March 6, 2007, we acquired all of the outstanding capital stock of JetStar Consolidated Holdings, Inc. (“JetStar”) for an aggregate purchase price of approximately $127.3 million, including $86.3 million in cash, of which approximately $37.6 million was used for the retirement of JetStar’s outstanding debt. As part of the purchase price, we issued 1,794,759 shares of common stock, at a fair value of $22.86 per share for a total fair value of approximately $41 million. This acquisition operates in our completion and remedial services line of business.

Sledge Drilling Holding Corp.

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

Selected 2008 Acquisitions

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

Xterra Fishing and Rental Tools Co

     On January 28, 2008, we acquired all of the outstanding capital stock of Xterra Fishing and Rental Tools Co. (“Xterra”) for total consideration of $21.1 million cash. This acquisition operates in our completion and remedial services line of business.

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Azurite Services Company, Inc.

     On September 26, 2008, we acquired substantially all of the operating assets of Azurite for $60.0 million in cash. This acquisition operates in our fluid services line of business.

Segment Overview

Well Servicing

     During the first nine months of 2008, our well servicing segment represented 35% of our revenues. Revenue in our well servicing segment is derived from maintenance, workover, completion, and plugging and abandonment services. We provide maintenance-related services as part of the normal, periodic upkeep of producing oil and gas wells. Maintenance-related services represent a relatively consistent component of our business. Workover and completion services generate more revenue per hour than maintenance work, due to the use of auxiliary equipment, but demand for workover and completion services fluctuates more with the overall activity level in the industry.

     We typically charge our customers for services on an hourly basis at rates that are determined by the type of service and equipment required, market conditions in the region in which the rig operates, the ancillary equipment provided on the rig and the necessary personnel. Depending on the type of job, we may also charge by the project or by the day. We measure our activity levels by the total number of hours worked by all of the rigs in our fleet. We monitor our fleet utilization levels, with full utilization deemed to be 55 hours per week per rig. Our fleet has increased from a weighted average number of 364 rigs in the first quarter of 2007 to 412 in the third quarter of 2008 through a combination of newbuild purchases and the remainder through acquisitions and other individual equipment purchases.

     The following is an analysis of our well servicing operations for each of the quarters and year ended December 31, 2007 and the quarters ended March 31, 2008, June 30, 2008, and September 30, 2008:

	Weighted
	Average				Rig					Profits
	Number of		Rig		Utilization			Revenue Per		Per Rig		Segment
	Rigs		Hours		Rate			Rig Hour		Hour		Profits%
2007:
First Quarter		364		210,800		81.0	%	$	411	$	174		42.2	%
Second Quarter		371		207,700		78.3	%	$	415	$	163		39.5	%
Third Quarter		383		212,100		77.7	%	$	414	$	166		40.0	%
Fourth Quarter		386		200,600		72.7	%	$	409	$	159		38.8	%
Full Year		376		831,200		77.3	%	$	412	$	166		40.1	%
2008:
First Quarter		392		202,500		72.2	%	$	398	$	158		39.8	%
Second Quarter		403		222,300		77.1	%	$	400	$	152		37.9	%
Third Quarter		412		233,000		79.1	%	$	418	$	156		37.3	%

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

     The increase in our revenue per rig hour to $418 in the third quarter of 2008 from $400 in the second quarter of 2008 is the result of a general rate increase along with an increase in the fuel surcharge to customers to offset rising fuel costs, when appropriate.

Fluid Services

     During the first nine months of 2008, our fluid services segment represented 30% 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, and well site construction and maintenance services. The fluid services segment has a base level of business consisting of transporting and disposing of salt water produced as a by-product of the production of oil and gas. These services are necessary for our customers and generally have a stable demand but typically produce lower relative segment profits than other parts of our fluid services segment. Fluid services for completion and workover projects typically require fresh or brine water for making drilling mud, circulating fluids or frac fluids used during a job, and all of these fluids require storage tanks and hauling and disposal. Because we can provide a full complement of fluid sales, trucking, storage and disposal required on most drilling and workover projects, the add-on services associated with drilling and workover activity enable us to generate higher segment profits contributions. Revenues from our well site construction services are derived primarily from preparing and maintaining access roads and well locations, installing small diameter gathering lines and pipelines, constructing foundations to support drilling rigs and providing maintenance services for oil and gas facilities. The higher segment profits are due to the relatively small incremental labor costs associated with providing these

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services in addition to our base fluid services segment. We typically price fluid services by the job, by the hour or by the quantities sold, disposed of or hauled.

     The following is an analysis of our fluid services operations for each of the quarters and year ended December 31, 2007 and the quarters ended March 31, 2008, June 30, 2008, and September 30, 2008 (dollars in thousands):

					Segment
					Profits
	Weighted				Per
	Average Number of		Revenue Per		Fluid
	Fluid Service		Fluid Service		Service		Segment
	Trucks		Truck		Truck		Profits%
2007:
First Quarter		652	$	98	$	37		37.5	%
Second Quarter		657	$	96	$	35		36.1	%
Third Quarter		653	$	97	$	35		35.7	%
Fourth Quarter		656	$	104	$	37		35.7	%
Full Year		655	$	396	$	144		36.2	%
2008:
First Quarter		644	$	111	$	39		35.0	%
Second Quarter		663	$	109	$	36		33.1	%
Third Quarter		683	$	121	$	43		35.8	%

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

     The increase in revenue per fluid service truck from $97,000 in the third quarter of 2007 to $121,000 in the third quarter of 2008 is primarily due to the retirement of less efficient and underutilized trucks in the fourth quarter of 2007, as well as the addition of 22 trucks from the Steve Carter Inc. and Hughes Services Inc. acquisition and 17 trucks from the B&S Equipment, Ltd. acquisition. There were also increases in the fuel surcharge charged to customers, as well as increases in rental rates for frac tanks.

Completion and Remedial Services

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

     Our pressure pumping operations concentrate on providing single truck, lower-horsepower cementing, acidizing and fracturing services in selected markets. In March 2007, we acquired all of the outstanding capital stock of JetStar Consolidated Holdings, Inc. This acquisition allowed us to enter into the Kansas market and increased our presence in North Texas. Our total hydraulic horsepower capacity for our pressure pumping operations was 134,000 and 121,000 at September 30, 2008 and September 30, 2007, respectively.

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

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

			Segment
	Revenues		Profits%
2007:
First Quarter	$	46,137		49.9	%
Second Quarter	$	63,735		47.6	%
Third Quarter	$	66,304		47.6	%
Fourth Quarter	$	64,515		46.2	%
Full Year	$	240,692		47.7	%
2008:
First Quarter	$	68,458		47.7	%
Second Quarter	$	79,579		46.4	%
Third Quarter	$	85,541		45.3	%

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

     The increase in completion and remedial services revenues from $66.3 million in the third quarter of 2007 to $85.5 million in the third quarter of 2008 is due to the Xterra and Triple N acquisitions, as well as internal expansion. Segment profits declined from the third quarter of 2007 to the same period in 2008, mainly due to increased costs of the materials used in our pressure pumping operations.

Contract Drilling

     During the first nine months of 2008, our contract drilling segment represented 4% of our revenues. Revenues from our contract drilling segment are derived primarily from the drilling of new wells.

     Within this segment, we typically charge our drilling rig customers at a “daywork” daily rate, or footage at an established rate per number of feet drilled. Depending on the type of job, we may also charge by the project. We measure the activity level of our drilling rigs on a weekly basis by calculating a rig utilization rate which is based on a seven day work week per rig. Our contract drilling rig fleet grew from a weighted average of three during the first quarter of 2007 to nine in the third quarter 2008. This increase is due to the Sledge acquisition in April 2007.

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

							��
	Weighted
	Average		Rig
	Number of		Operating		Revenue		Profits (Loss)			Segment
	Rigs		Days		Per Day		Per Day			Profits%
2007:
First Quarter		3		168	$	11,500	$	(5,200	)		-44.9	%
Second Quarter		8		594	$	17,200	$	6,900			39.5	%
Third Quarter		9		723	$	15,700	$	6,700			42.4	%
Fourth Quarter		10		748	$	14,600	$	5,300			36.3	%
Full Year		8		2,233	$	15,400	$	5,400			34.7	%
2008:
First Quarter		9		645	$	14,700	$	3,800			25.7	%
Second Quarter		9		699	$	14,800	$	4,000			27.2	%
Third Quarter		9		767	$	15,600	$	5,600			35.6	%

     We gauge activity levels in our drilling operations based on rig operating days, revenue per day and profits per drilling day.

     The decrease in segment profits from 42.4% in the third quarter of 2007 to 35.6% in the third quarter of 2008 is due to the decrease in profits per day from $6,700 in the third quarter of 2007 to $5,600 in the third quarter of 2008 due to higher operating expenses.

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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 in the long-term to compensate for wage rate increases. We also incur costs to employ personnel to sell and supervise our services and perform maintenance on our fleet. These costs are not directly tied to our level of business activity. Compensation for our administrative personnel in local operating yards and in our corporate office is accounted for as general and administrative expenses. Repair and maintenance is performed by our crews, company maintenance personnel and outside service providers. Insurance is generally a fixed cost regardless of utilization and relates to the number of rigs, trucks and other equipment in our fleet, employee payroll and safety record.

Critical Accounting Policies and Estimates

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

Critical Accounting Policies

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

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

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

     Self-Insured Risk Accruals.We are self-insured up to retention limits with regard to workers’ compensation and medical and dental coverage of our employees. We generally maintain no physical property damage coverage on our workover rig fleet, with the exception of certain of our 24-hour workover rigs and newly manufactured rigs. We have deductibles per occurrence for workers’ compensation and medical and dental coverage of $375,000 and $180,000 respectively. We have lower deductibles per occurrence for automobile liability and general liability. We maintain accruals in our consolidated balance sheets related to self-insurance retentions by using third-party actuarial data and historical claims history.

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

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

Critical Accounting Estimates

     The preparation of our consolidated financial statements in conformity with accounting principles generally accepted in the United States of America (GAAP) requires management to make certain estimates and assumptions. These estimates and assumptions affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the balance sheet date and the

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

     Fair Value of Assets Acquired and Liabilities Assumed.We estimate the fair value of assets acquired and liabilities assumed in business combinations, which involves the use of various assumptions. These estimates may be affected by such factors as changing market conditions, technological advances in industry or changes in regulations governing the industry. The most significant assumptions, and the ones requiring the most judgment, involve the estimated fair value of property and equipment, intangible assets and the resulting amount of goodwill, if any. Our adoption of SFAS No. 142 on January 1, 2002 requires us to test annually for impairment the goodwill and intangible assets with indefinite useful lives recorded in business combinations. 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.Basic accounts for stock-based compensation based on Statement of Financial Accounting Standards No. 123 (revised 2004),“Share Based Payment”(“SFAS No. 123R”). Options issued are valued on the grant date using the Black-Scholes-Merton option-pricing model and all awards are adjusted for an expected forfeiture rate. Awards are amortized over the vesting period. Compensation expense of the unvested portion of awards granted as a private company and outstanding as of January 1, 2006 will be based upon the intrinsic value method calculated under APB No. 25.

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

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

     Asset Retirement Obligations.SFAS No. 143 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

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

Results of Operations

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

     Three Months Ended September 30, 2008 Compared to Three Months Ended September 30, 2007

     Revenues.Revenues increased by 21% to $277.6 million during the third quarter of 2008 from $229.2 million during the same period in 2007. This increase was primarily due to expansion through acquisitions, particularly in the completion and remedial services segment and fluid services segment.

     Well servicing revenues increased by 11% to $97.4 million during the third quarter of 2008 compared to $87.9 million during the same period in 2007. Our average number of well servicing rigs increased to 412 during the third quarter of 2008 compared to 383 in the same period in 2007, due to internal expansion from our newbuild rig program and the Lackey Construction, LLC and the Triple N Services, Inc. acquisitions. Our revenue per rig hour also increased to $418 during the third quarter of 2008 from $414 during the third quarter of 2007. During the third quarter of 2008, we added five newbuid rigs and retired one rig.

     Fluid services revenues increased by 30% to $82.7 million during the third quarter of 2008 compared to $63.7 million in the same period in 2007. This increase was primarily due to internal growth and acquisitions, particularly the Steve Carter Inc. and Hughes Services Inc. (“Carter and Hughes”) acquisition in September 2007 which added 22 fluid service trucks and other equipment. This acquisition added approximately $3.5 million more of revenues during the third quarter of 2008 compared to the same period in 2007. Our weighted average number of fluid service trucks increased to 683 during the third quarter of 2008 from 653 in the same period in 2007 and our revenue per fluid service truck increased to $121,000 in the third quarter of 2008 compared to $97,000 in the same period in 2007. The increase in revenue per truck was primarily due to the retirement of a number of under utilized and less efficient fluid service trucks in the fourth quarter of 2007 and higher fuel surcharges and other services which are not directly correlated with trucking volume, such as frac tank rentals.

     Completion and remedial services revenues increased by 29% to $85.5 million during the third quarter of 2008 compared to $66.3 million in the same period in 2007. The increase in revenue between these periods was primarily the result of the Xterra Fishing and Rental Tools Co. and Triple N Services, Inc. acquisitions. Total hydraulic horsepower also increased to 134,000 at September 30, 2008 from 121,000 at September 30, 2007.

     Contract drilling revenues increased by 5% to $12.0 million during the third quarter in 2008 compared to $11.4 million in the same period in 2007. The number of rig operating days increased to 767 in third quarter of 2008 compared to 723 in the third quarter of 2007.

     Direct Operating Expenses.Direct operating expenses, which primarily consist of labor, including workers compensation and health insurance, fuel and maintenance and repair costs, increased by 25% to $168.6 million during the third quarter of 2008 from $135.0 million in the same period in 2007. This increase is due to the acquisitions we have made, as well as higher personnel related and other operating costs in all of our business segments.

     Direct operating expenses for the well servicing segment increased by 16% to $61.0 million during the third quarter of 2008 as compared to $52.8 million for the same period in 2007, due primarily to increased rig hours to 233,000 in the third quarter of 2008 from 212,100 for the same period in 2007. Segment profits decreased to 37% of revenues during the third quarter of 2008 compared to 40% for the same period in 2007, which reflects higher fuel costs as well as higher labor costs.

     Direct operating expenses for the fluid services segment increased by 30% to $53.0 million during the third quarter of 2008 as compared to $40.9 million for the same period in 2007, which is due to higher activity levels. Segment profits were 36% of revenues during the third quarter of 2008 and 2007. Higher fuel costs were offset by income from an increase in the fuel surcharge, which helped maintain a level segment profit percentage.

     Direct operating expenses for the completion and remedial services segment increased by 35% to $46.8 million during the third quarter of 2008 as compared to $34.7 million for the same period in 2007 due primarily to expansion of our services and equipment through acquisitions as noted above. Segment profits decreased to 45% of revenues during the third quarter of 2008 compared to 48%

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for the same period in 2007, due to higher fuel costs and increases in the cost of the materials used in our pressure pumping operations.

     Direct operating expenses for the contract drilling segment increased by 18% to $7.7 million during the third quarter of 2008 as compared to $6.6 million for the same period in 2007 due primarily to higher personnel costs and higher fuel costs. Segment profits for this segment were 36% of revenues during the third quarter of 2008 compared to 42% for the same period in 2007.

     General and Administrative Expenses.General and administrative expenses increased by 20% to $30.6 million during the third quarter of 2008 from $25.5 million for the same period in 2007, which included $1.2 million and $1.1 million in stock-based compensation expense for 2008 and 2007, respectively. The increase primarily reflects higher salary and office expenses related to the expansion of our business.

     Depreciation and Amortization Expenses.Depreciation and amortization expenses were $29.3 million during the third quarter of 2008 as compared to $23.6 million for the same period in 2007, reflecting the increase in the size of and investment in our asset base, due to acquisitions as well as through the internal expansion of our business segments.

     Interest Expense.Interest expense decreased by 14% to $6.3 million during the third quarter of 2008 compared to $7.4 million for the same period in 2007. The decrease was due primarily to lower interest rates on our revolving line of credit.

     Other Income and Expense.Other income and expense includes $6.3 million of merger costs associated with the terminated merger agreement with Grey Wolf, Inc., offset by a termination payment received from Grey Wolf, Inc. for $5.0 million in July 2008.

     Income Tax Expense.Income tax expense was $15.9 million during the third quarter of 2008 as compared to $14.2 million for the same period in 2007. Our effective tax rate during the third quarter of 2008 and 2007 was approximately 38% and 37%, respectively.

     Nine Months Ended September 30, 2008 Compared to Nine Months Ended September 30, 2007

     Revenues.Revenues increased by 17% to $759.0 million during the first nine months of 2008 from $651.4 million during the same period in 2007. This increase was primarily due to expansion through acquisitions, particularly in the completion and remedial services business segment.

     Well servicing revenues increased by 2% to $266.9 million during the first nine months of 2008 compared to $260.7 million during the same period in 2007. The increase is mainly due to the increase in rig hours to 657,800 for the first nine months of 2008 compared to 630,600 for the first nine months of 2007. This increase in hours was offset by a decrease in revenue per rig hour to $406 for the first nine months of 2008 from $413 for the fist nine months of 2007. Our average number of well servicing rigs increased to 402 during the first nine months of 2008 compared to 373 in the same period in 2007, mainly due to internal expansion from our newbuild rig program. During the first nine months of 2008, we added 17 newbuilds and 13 well servicing rigs from acquisitions, converted one drilling rig to workover mode and also retired five well servicing rigs.

     Fluid services revenues increased by 19% to $226.6 million during the first nine months of 2008 compared to $191.0 million in the same period of 2007. This increase was primarily due to internal growth and acquisitions, particularly the Carter and Hughes acquisition. This acquisition added approximately $9.1 million in revenues in 2008. Our weighted average number of fluid service trucks increased to 663 during the first nine months of 2008 from 654 in the same period in 2007. Our revenue per fluid service truck increased to $342,000 in the first nine months of 2008 compared to $292,000 in same period in 2007. The increase in revenue per truck was primarily due to rate increases and increases in the fuel surcharge to customers to offset rising fuel costs.

     Completion and remedial services revenues increased by 33% to $233.6 million during the first nine months of 2008 compared to $176.2 million in the same period in 2007. The increase in revenue between these periods was primarily the result of acquisitions, the largest being JetStar in March 2007, which added approximately $18.9 million more in revenues in the first nine months of 2008 compared to the same period in 2007. There was also an increase in hydraulic horsepower for pressure pumping to 134,000 at September 30, 2008 from 121,000 at September 30, 2007.

     Contract drilling revenues increased by 35% to $31.8 million during the first nine months of 2008 as compared to $23.5 million in the same period in 2007. The majority of this increase was due to the acquisition of Sledge in April 2007 which added approximately $3.3 million more in revenues during the first nine months of 2008 as compared to the same period in 2007. Our weighted average number of drilling rigs increased to nine in the first nine months of 2008 as compared to seven in the same period in 2007.

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     Direct Operating Expenses.Direct operating expenses, which primarily consist of labor, including workers compensation and health insurance, fuel and maintenance and repair costs, increased by 20% to $460.4 million during the first nine months of 2008 from $383.1 million in the same period in 2007. This increase was primarily due to the acquisitions that we have made, as well as higher personnel related and other operating costs in all of our business segments.

     Direct operating expenses for the well servicing segment increased by 6% to $164.8 million during the first nine months of 2008 as compared to $154.9 million for the same period in 2007, due primarily to increased rig hours to 657,800 in the first nine months of 2008 from 630,600 for the same period in 2007. Segment profits decreased to 38% of revenues during the first nine months of 2008 compared to 41% for the same period in 2007, which reflects higher fuel costs, as well as higher labor costs.

     Direct operating expenses for the fluid services segment increased by 22% to $148.0 million during the first nine months of 2008 as compared to $121.4 million for the same period in 2007 due in part to higher fuel costs. Segment profits decreased to 35% of revenues during the first nine months of 2008 compared to 36% for the same period in 2007.

     Direct operating expenses for the completion and remedial services segment increased by 37% to $125.2 million during the first nine months of 2008 as compared to $91.2 million for the same period in 2007 due primarily to expansion of our services and equipment, including the JetStar acquisition. The JetStar acquisition added approximately $16.9 million more of direct operating expenses during the first nine months of 2008 compared to the same period in 2007. Segment profits decreased to 46% of revenues during the first nine months of 2008 compared to 48% for the same period in 2007, due to higher fuel costs and increases in the cost of the materials used in our pressure pumping operations.

     Direct operating expenses for the contract drilling segment increased by 43% to $22.3 million during the first nine months of 2008 as compared to $15.6 million for the same period in 2007. The Sledge acquisition added approximately $5.9 million more of direct operating expense during the first nine months of 2008 compared to the same period in 2007. Segment profits for this segment were 30% of revenues during the first nine months of 2008 and 34% of revenues during the first nine months of 2007.

     General and Administrative Expenses.General and administrative expenses increased by 13% to $83.2 million during the first nine months of 2008 from $73.7 million for the same period in 2007, which included $3.4 million and $3.2 million in stock-based compensation expense for 2008 and 2007, respectively. The increase primarily reflects higher salary and office expenses related to the expansion of our business.

     Depreciation and Amortization Expenses.Depreciation and amortization expenses were $86.0 million during the first nine months of 2008 as compared to $66.8 million for the same period in 2007, reflecting the increase in the size of and investment in our asset base, primarily through acquisitions as well as through the internal expansion of our business segments.

     Interest Expense.Interest expense decreased by less than 1% to $20.1 million during the first nine months of 2008 compared to $20.2 million for the same period in 2007.

     Other Income and Expense.Other income and expense includes $7.9 million of merger costs associated with the terminated merger agreement with Grey Wolf, Inc., net of a termination payment of $5.0 million received in July 2008.

     Income Tax Expense.Income tax expense was $39.3 million during the first nine months of 2008 as compared to $40.8 million for the same period in 2007. Our effective tax rate during the first nine months of 2008 and 2007 was approximately 38% and 37%, respectively.

Liquidity and Capital Resources

     Currently, our primary capital resources are net cash flows from our operations, utilization of capital leases as allowed under our 2007 Credit Facility and availability under our 2007 Credit Facility, of which approximately $28.8 million was available at September 30, 2008. As of September 30, 2008, we had cash and cash equivalents of $80.9 million compared to $91.9 million as of December 31, 2007. We have utilized, and expect to utilize in the future, bank and capital lease financing and sales of equity to obtain capital resources. We believe that, if needed, we will have access to this financing despite declines in debt markets. When appropriate, we will also 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 $143.5 million for the nine months ended September 30, 2008 as compared to $144.0 million during the same period in 2007. Operating cash flow was relatively flat due to the increase in revenues being offset by a corresponding increase in accounts receivable.

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Capital Expenditures

     Capital expenditures are the main component of our investing activities. Cash capital expenditures (including acquisitions) during the first nine months of 2008 were $179.7 million as compared to $276.5 million in the same period of 2007. We added $35.7 million of additional assets through our capital lease program during the first nine months of 2008 compared to $20.1 million in the same period in 2007.

     For 2008, we currently have planned approximately $95 million in cash capital expenditures and $40 million in capital leases, none of which is planned for acquisitions. We do not budget acquisitions in the normal course of business, but we believe that given current market conditions, opportunities to acquire companies could be present. The $135 million of capital expenditures planned for property and equipment is primarily for (1) purchase of additional equipment to expand our services, (2) continued refurbishment of our well servicing rigs and (3) replacement of existing equipment. We regularly engage in discussions related to potential acquisitions related to the well services industry.

Capital Resources and Financing

     Our current primary capital resources are cash flow from our operations, the ability to enter into capital leases of up to an additional $84.6 million at September 30, 2008, the availability under our credit facility of $28.8 million at September 30, 2008 and a cash balance of $80.9 million at September 30, 2008. During the first nine months of 2008, we financed activities in excess of cash flow from operations primarily through the use of bank debt and capital leases.

     At September 30, 2008, of the $225.0 million in financial commitments under the revolving line of credit under our 2007 Credit Facility, there was $28.8 million of available capacity due to the outstanding balance of $180.0 million and the $16.2 million of outstanding standby letters of credit. The 2007 Credit Facility includes provisions allowing us to request an increase in commitments of up to $100.0 million aggregate principal amount at any time. Additionally, the 2007 Credit Facility permits us to make greater expenditures for acquisitions, capital expenditures and capital leases and to incur greater purchase money obligations, acquisition indebtedness and general unsecured indebtedness.

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

Senior Notes

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

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

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

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

• incur additional indebtedness;

• pay dividends or repurchase or redeem capital stock;

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• make certain investments;

• incur liens;

• enter into certain types of transactions with affiliates;

• limit dividends or other payments by restricted subsidiaries; and

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

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

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

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

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

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

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

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

Credit Facilities

2007 Credit Facility

     On February 6, 2007, we amended and restated our existing credit agreement by entering into a Fourth Amended and Restated Credit Agreement with a syndicate of lenders (the “2007 Credit Facility”). The amendments contained in the 2007 Credit Facility included:

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

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

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

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

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

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

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

     Under the 2007 Credit Facility, Basic Energy Services, Inc. is the sole borrower and each of our subsidiaries is a subsidiary guarantor. The 2007 Credit Facility provides for a $225 million revolving line of credit (“Revolver”). The 2007 Credit Facility includes provisions allowing us to request an increase in commitments of up to $100.0 million aggregate principal amount at any time. Additionally, the 2007 Credit Facility permits us to make greater expenditures for acquisitions, capital expenditures and capital leases and to incur greater purchase money obligations, acquisition indebtedness and general unsecured indebtedness. The commitment under the Revolver provides for (1) the borrowing of funds, (2) the issuance of up to $30 million of letters of credit and (3) $2.5 million of swing-line loans. All of the outstanding amounts under the Revolver are due and payable on December 15, 2010. The 2007 Credit Facility is secured by substantially all of our tangible and intangible assets. We incurred approximately $0.7 million in debt issuance costs in connection with the 2007 Credit Facility.

     At our option, borrowings under the Revolver bears interest at either (1) the “Alternative Base Rate” (i.e., the higher of the bank’s prime rate or the federal funds rate plus .50% per year) plus a margin ranging from 0.25% to 0.5% or (2) an “Adjusted LIBOR Rate” (equal to (a) the London Interbank Offered Rate (the “LIBOR rate”) as determined by the Administrative Agent in effect for such interest period divided by (b) one minus the Statutory Reserves, if any, for such borrowing for such interest period) plus a margin ranging from 1.25% to 1.5%. The margins vary depending on our leverage ratio. Fees on the letters of credit are due quarterly on the outstanding amount of the letters of credit at a rate ranging from 1.25% to 1.5% for participation fees and 0.125% for fronting fees. A commitment fee is due quarterly on the available borrowings under the Revolver at a rate of 0.375%.

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

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

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

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

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

• limitations on the incurrence of additional indebtedness;

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

• limitations on dividends and distributions; and

• various financial covenants, including:

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

• a minimum interest coverage ratio of 3.00 to 1.00.

Other Debt

     We have a variety of other capital leases and notes payable outstanding that is generally customary in our business. None of these debt instruments are material individually or in the aggregate. As of September 30, 2008, we had total capital leases of approximately $67.4 million.

Credit Rating Agencies

     Our Senior Notes are currently rated BB- and B1 by Standard and Poor’s and Moody’s, respectively. Our 2007 Credit Facility maintains ratings of BB+ and Ba1 from Standard and Poor’s and Moody’s, respectively.

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Preferred Stock

     At September 30, 2008 and December 31, 2007, we had 5,000,000 shares of $.01 par value preferred stock authorized, of which none was designated.

Other Matters

Net Operating Losses

     As of September 30, 2008, we had approximately $2.3 million of NOL carryforwards related to the pre-acquisition period of a 2003 acquisition, which is subject to an annual limitation of approximately $900,000. The carryforwards begin to expire in 2017.

Recent Accounting Pronouncements

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

     In February 2007, the FASB issuedSFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities (SFAS 159), which became effective for the company on January 1, 2008. This standard permits companies to choose to measure many financial instruments and certain other items at fair value and report unrealized gains and losses in earnings. Such accounting is optional and is generally to be applied instrument by instrument. The company does not anticipate that the adoption of SFAS 159 will have a material effect on its results of operations or consolidated financial position.

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

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

     In March 2008, the FASB issued SFAS No. 161,Disclosures about Derivative Instruments and Hedging Activities(SFAS 161), which becomes effective for the Company on January 1, 2009. This standard improves financial reporting for derivative instruments and hedging activities by requiring enhanced disclosures to expand on these instruments’ effects on the company’s financial position, financial performance and cash flows. The Company does not anticipate that this pronouncement will have a material impact on its results of operations or consolidated financial position.

     In May 2008, the FASB issued SFAS No. 162,The Hierarchy of Generally Accepted Accounting Principles(SFAS 162), which becomes effective for the Company 60 days following the SEC’s approval of the Public Company Accounting Oversight Board amendments to AU Section 411,The Meaning of Present Fairly in Conformity With General Accepted Accounting Principles. This standard identifies the sources of accounting principles and the framework for selecting the principles used in the preparation of

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financial statements that are presented in conformity with generally accepted accounting principles (GAAP). The Company does not anticipate that this pronouncement will have a material impact on its results of operations or consolidated financial position.

     In June 2008, the FASB issued FASB Staff Position EITF 03-6-1“Determining Whether Instruments Granted in Share-Based Payment Transactions are Participating Securities”(“FSP EITF 03-6-1”). FSP EITF 03-6-1 addresses whether instruments granted in share-based payment transactions are participating securities prior to vesting and, therefore, need to be included in the earnings allocation in computing earnings per share (“EPS”) under the two-class method described in paragraphs 60 and 61 of SFAS No. 128, “Earnings Per Share”. FSP EITF 03-6-1 is effective for financial statements issued for fiscal years and interim periods beginning after December 15, 2008 and requires retrospective adjustment for all comparable prior periods presented. The Company does not anticipate that the adoption of FSP EITF 03-6-1 will have a material impact on its EPS disclosures.

Impact of Inflation on Operations

     Management is of the opinion that inflation has not had a significant impact on our business, other than increases in fuel costs and personnel expenses that are discussed previously in the Management’s Discussion and Analysis.

ITEM 3.QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

     As of September 30, 2008, we had $180.0 million outstanding under the revolving portion of our credit facility subject to variable interest rate risk. The impact of a 1% increase in interest rates on this amount of debt would result in increased interest expense of approximately $1.8 million annually and a decrease in net income of approximately $1.1 million.

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ITEM 4.CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

     Based on their evaluation as of the end of the period covered by this report, 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 and effective to ensure that information required to be disclosed in such reports is accumulated and communicated to our management, including our principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure.

Changes in 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

     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.

ITEM 1A.RISK FACTORS

     For information regarding risks that may affect our business, see the risk factors included in our most recent annual report on Form 10-K under the heading “Risk Factors.” The following is an additional important factor that could affect our financial performance or could cause actual results to differ materially from estimates contained in our forward-looking statements. We may encounter risks in addition to the one described below. Additional risks and uncertainties not currently known to us, or that we currently deem to be immaterial, may also impair or adversely affect our business, results of operation, financial condition and prospects.

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

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

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

     Recent adverse changes in capital markets have also caused a number of oil and gas producers to announce reductions in capital budgets for future periods.  Limitations on the availability of capital, or higher costs of capital, for financing expenditures may cause these and other oil and gas producers to make additional reductions to capital budgets in the future even if commodity prices remain at historically high levels.

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

Purchase of Equity Securities by the Issuer and Affiliated Purchasers

     The following table summarizes stock repurchase activity for the three months ended September 30, 2008:

Issuer Purchases of Equity Securities
					Total Number of		Maximum Number of
					Shares Purchased as		Shares that May Yet
					Part of Publicly		be Purchased Under
	Total Number of		Average Price Paid per		Announced Plans or		the Plans or
Period	Shares Purchased		Share		Programs		Programs
July 1 – July 31		—		—		—		—
August 1 – August 31 (1)		1,157	$	25.77		—		—
September 1 – September 30		—		—		—		—
Total		1,157	$	25.77		—		—

(1) These shares were repurchased from one of our officers to provide such officer the cash amounts necessary to pay certain tax liabilities associated with the vesting of restricted shares owned by him. The shares were repurchased effective August 8, 2008, based on the closing price per share on August 8, 2008.

ITEM 4.SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

     We held a Special Meeting of Stockholders (the “Special Meeting”) on July 15, 2008 in Houston, Texas to adopt the Plan of Merger (the “Merger Agreement”) previously entered into among Basic, Grey Wolf and Horsepower Holdings, Inc. on April 20, 2008 pursuant to Section 7.1(b)(iii) of the Merger Agreement, to approve the Horsepower Holdings, Inc. 2008 Equity Incentive Plan, and to approve the adjournment of the Special Meeting, if necessary or appropriate, to solicit additional proxies in favor. A total of 36,106,324 shares of our common stock were present at the meeting in person or by proxy, which represented 87.4% of the outstanding shares of our common stock as of June 6, 2008, the record date for the Special Meeting.

     The Merger Agreement was approved at the Special Meeting based on the following vote tabulation:

For	Against	Abstentions
35,587,411	514,515	4,368

     The Horsepower Holdings, Inc. 2008 Equity Incentive Plan was adopted at the Special Meeting based on the following vote tabulation:

For	Against	Abstentions
30,938,238	5,160,016	8,070

     The adjournment of the Special Meeting, if necessary, was approved at the Special Meeting based on the following vote tabulation:

For	Against	Abstentions
35,264,223	837,423	4,678

     We held our Annual Meeting of Stockholders (the “Annual Meeting”) on September 16, 2008 in Houston, Texas to elect three directors to serve until the Annual Meeting of Stockholders in 2011 and to approve the ratification of the appointment of KPMG LLP as our independent auditor for fiscal year 2008. A total of 39,586,827 shares of our common stock were present at the meeting in person or by proxy, which represented 95.8% of the outstanding shares of our common stock as of August 5, 2008, the record date for the Annual Meeting.

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     Director nominees were elected at the Annual Meeting based on the following vote tabulation:

	Votes in Favor		Votes Withheld
James S. D’Agostino		39,244,223		342,604
Kenneth V. Huseman		38,968,736		618,091
Thomas P. Moore, Jr.		39,243,776		343,051

     The directors with terms of office continuing after the Annual Meeting are as follows:

Directors with terms expiring in 2009

Sylvester P. Johnson, IV
Steven A. Webster
H.H. Wommack, III

Directors with terms expiring in 2010

William E. Chiles
Robert F. Fulton

      Stockholders approved the ratification of the appointment of KPMG LLP as our independent auditor for fiscal year 2008 at the Annual Meeting based on the following vote tabulation:

For	Against	Abstentions
39,533,061	36,536	17,229

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ITEM 6.EXHIBITS

Exhibit
No.	Description
2.1*	Agreement and Plan of Merger, dated as of April 20, 2008, by and among Basic Energy Services, Inc. (the “Company”), Grey Wolf, Inc. and Horsepower Holdings, Inc. (Incorporated by reference to Exhibit 2.1 of the Company’s Current Report on Form 8-K (SEC File No. 001-32693), filed on April 22, 2008)
3.1*	Amended and Restated Certificate of Incorporation of the Company, dated September 22, 2005. (Incorporated by reference to Exhibit 3.1 of the Company’s Registration Statement 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)
3.3*	Amended and Restated Bylaws of the Company, effective as of December 17, 2007. (Incorporated by reference to Exhibit 3.1 of the Company’s Current Report on Form 8-K (SEC File No. 001-32693), filed on December 18, 2007)
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 the Company, 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)
4.4*	First Supplemental Indenture dated as of July 14, 2006 to Indenture dated as of April 12, 2006 among the Company, as Issuer, the Subsidiary Guarantors named therein and The Bank of New York Trust Company, N.A., as trustee. (Incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K (SEC File No. 001-32693), filed on July 20, 2006)
4.5*	Second Supplemental Indenture dated as of April 26, 2007 and effective as of March 7, 2007 to Indenture dated as of April 12, 2006 among the Company as Issuer, the Subsidiary Guarantors named therein and the Bank of New York Trust Company, N.A., as trustee. (Incorporated by reference to Exhibit 4.1 of the Company’s Current Report on form 8-K (SEC File No 001-32693), filed on May 1, 2007)
4.6*	Third Supplemental Indenture dated as of April 26, 2007 to Indenture dated as of April 12, 2006 among the Company as Issuer, the Subsidiary Guarantors named therein and the Bank of New York Trust Company, N.A., as trustee. (Incorporated by reference to Exhibit 4.2 of the Company’s Current Report on Form 8-K (SEC File No 001-32693), filed on May 1, 2007)
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 of 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

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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, Treasurer and Secretary (Principal
		Financial Officer and Principal Accounting Officer)

Date: November 5, 2008

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Exhibit Index

Exhibit
No.	Description
2.1*	Agreement and Plan of Merger, dated as of April 20, 2008, by and among Basic Energy Services, Inc. (the “Company”), Grey Wolf, Inc. and Horsepower Holdings, Inc. (Incorporated by reference to Exhibit 2.1 of the Company’s Current Report on Form 8-K (SEC File No. 001-32693), filed on April 22, 2008)
3.1*	Amended and Restated Certificate of Incorporation of the Company, dated September 22, 2005. (Incorporated by reference to Exhibit 3.1 of the Company’s Registration Statement 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)
3.3*	Amended and Restated Bylaws of the Company, effective as of December 17, 2007. (Incorporated by reference to Exhibit 3.1 of the Company’s Current Report on Form 8-K (SEC File No. 001-32693), filed on December 18, 2007)
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 the Company, 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)
4.4*	First Supplemental Indenture dated as of July 14, 2006 to Indenture dated as of April 12, 2006 among the Company, as Issuer, the Subsidiary Guarantors named therein and The Bank of New York Trust Company, N.A., as trustee. (Incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K (SEC File No. 001-32693), filed on July 20, 2006)
4.5*	Second Supplemental Indenture dated as of April 26, 2007 and effective as of March 7, 2007 to Indenture dated as of April 12, 2006 among the Company as Issuer, the Subsidiary Guarantors named therein and the Bank of New York Trust Company, N.A., as trustee. (Incorporated by reference to Exhibit 4.1 of the Company’s Current Report on form 8-K (SEC File No 001-32693), filed on May 1, 2007)
4.6*	Third Supplemental Indenture dated as of April 26, 2007 to Indenture dated as of April 12, 2006 among the Company as Issuer, the Subsidiary Guarantors named therein and the Bank of New York Trust Company, N.A., as trustee. (Incorporated by reference to Exhibit 4.2 of the Company’s Current Report on Form 8-K (SEC File No 001-32693), filed on May 1, 2007)
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 of 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

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