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 June 30, 2009

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

For the transition period from            to

Basic Energy Services, Inc.

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

     Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes  o     No o

     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):

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

     40,701,498 shares of the registrant’s Common Stock were outstanding as of July 24, 2009.

 

 

BASIC ENERGY SERVICES, INC.

Index to Form 10-Q

Part I. FINANCIAL INFORMATION			4
Item 1. Financial Statements			4
Consolidated Balance Sheets as of June 30, 2009 and December 31, 2008			4
Consolidated Statements of Operations and Comprehensive Income for the three months and six months ended June 30, 2009 and 2008			5
Consolidated Statements of Stockholders’ Equity for the six months ended June 30, 2009			6
Consolidated Statements of Cash Flows for the six months ended June 30, 2009 and 2008			7
Notes to the Consolidated Financial Statements			8
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			25
Management’s Overview			25
Segment Overview			27
Operating Cost Overview			30
Critical Accounting Policies and Estimates			30
Results of Operations			32
Liquidity and Capital Resources			34
Other Matters			37
Item 3. Quantitative and Qualitative Disclosures About Market Risk			39
Item 4. Controls and Procedures			39
Part II. OTHER INFORMATION			39
Item 1. Legal Proceedings			39
Item 1A. Risk Factors			39
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			40
Item 4. Submission of Matters to a Vote of Security Holders			40
Item 6. Exhibits			42
Signatures			43
EX-31.1
EX-31.2
EX-32.1
EX-32.2

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 and 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, and industry publications and surveys. Industry surveys and 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.

PART I — FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

Basic Energy Services, Inc.
Consolidated Balance Sheets
(in thousands, except share data)

		June 30,				December 31,
		2009				2008
		(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents		$	134,304			$	111,135
Trade accounts receivable, net of allowance of $6,396 and $5,838, respectively			98,997				172,930
Accounts receivable — related parties			138				148
Income tax receivable			27,052				3,324
Inventories			11,279				11,937
Prepaid expenses			4,615				6,838
Other current assets			5,648				6,508
Deferred tax assets			28,076				11,081
Total current assets			310,109				323,901
Property and equipment, net			714,560				740,879
Deferred debt costs, net of amortization			7,058				5,132
Goodwill			—				202,749
Other intangible assets, net of amortization			34,381				36,004
Other assets			2,285				2,046
Total assets		$	1,068,393			$	1,310,711
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable		$	17,784			$	28,291
Accrued expenses			37,950				47,139
Current portion of long-term debt			28,316				26,063
Other current liabilities			401				658
Total current liabilities			84,451				102,151
Long-term debt			451,958				454,260
Deferred tax liabilities			135,079				149,591
Other long-term liabilities			9,686				9,705
Commitments and contingencies
Stockholders’ equity:
Preferred stock; $.01 par value; 5,000,000 shares authorized; none designated or issued at June 30, 2009 and December 31, 2008, respectively			—				—
Common stock; $.01 par value; 80,000,000 shares authorized; 42,394,809 shares issued; and 40,703,187 shares outstanding at June 30, 2009; 41,734,485 shares issued; and 40,851,862 shares outstanding at December 31, 2008.			424				417
Additional paid-in capital			328,101				325,785
Retained earnings			72,642				277,173
Treasury stock, at cost, 1,691,622 and 882,623 shares at June 30, 2009 and December 31, 2008, respectively			(13,948	)			(8,371	)
Total stockholders’ equity			387,219				595,004
Total liabilities and stockholders’ equity		$	1,068,393			$	1,310,711

See accompanying notes to consolidated financial statements.

Basic Energy Services, Inc.
Consolidated Statements of Operations and Comprehensive Income
(in thousands, except per share amounts)

		Three Months Ended June 30,								Six Months Ended June 30,
		2009				2008				2009				2008
		(Unaudited)								(Unaudited)
Revenues:
Well servicing		$	36,399			$	89,018			$	85,213			$	169,537
Fluid services			49,088				72,581				114,065				143,980
Completion and remedial services			29,373				79,579				66,632				148,037
Contract drilling			3,988				10,344				7,626				19,841
Total revenues			118,848				251,522				273,536				481,395
Expenses:
Well servicing			27,825				55,293				64,742				103,759
Fluid services			35,381				48,554				79,968				94,987
Completion and remedial services			21,484				42,651				47,378				78,439
Contract drilling			3,338				7,529				6,607				14,589
General and administrative, including stock-based compensation of $1,290 and $1,184 in three months ended June 30, 2009 and 2008, and $2,665 and $2,264 in the six months ended June 30, 2009 and 2008, respectively			27,424				26,811				56,503				52,663
Depreciation and amortization			32,413				28,732				65,150				56,764
(Gain) loss on disposal of assets			474				(809	)			1,339				(584	)
Goodwill impairment			(82	)			—				204,014				—
Total expenses			148,257				208,761				525,701				400,617
Operating income (loss)			(29,409	)			42,761				(252,165	)			80,778
Other income (expense):
Interest expense			(5,974	)			(6,453	)			(11,710	)			(13,802	)
Interest income			173				471				393				1,172
Other income (expense)			118				(6,469	)			252				(6,431	)
Income (loss) from continuing operations before income taxes			(35,092	)			30,310				(263,230	)			61,717
Income tax benefit (expense)			13,856				(11,597	)			59,169				(23,348	)
Net income (loss)		$	(21,236	)		$	18,713			$	(204,061	)		$	38,369
Earnings per share of common stock:
Basic		$	(0.54	)		$	0.46			$	(5.13	)		$	0.94
Diluted		$	(0.54	)		$	0.45			$	(5.13	)		$	0.92

See accompanying notes to consolidated financial statements.

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, 2008			41,734,485			$	417			$	325,785			$	(8,371	)		$	277,173			$	595,004
Issuances of restricted stock			660,324				7				(7	)			431				(431	)			—
Amortization of share based compensation			—				—				2,640				—				—				2,640
Treasury stock issued as compensation to Chairman of the Board			—				—				—				43				(19	)			24
Purchase of treasury stock			—				—				—				(6,104	)			—				(6,104	)
Exercise of stock options / vesting of restricted stock			—				—				(317	)			53				(20	)			(284	)
Net loss			—				—				—				—				(204,061	)			(204,061	)
Balance — June 30, 2009 (unaudited)			42,394,809			$	424			$	328,101			$	(13,948	)		$	72,642			$	387,219

See accompanying notes to consolidated financial statements.

Basic Energy Services, Inc.
Consolidated Statements of Cash Flows
(in thousands)

		Six Months Ended June 30,
		2009				2008
		(Unaudited)
Cash flows from operating activities:
Net income (loss)		$	(204,061	)		$	38,369
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization			65,150				56,764
Goodwill impairment			204,014				—
Accretion on asset retirement obligation			73				63
Change in allowance for doubtful accounts			558				(483	)
Amortization of deferred financing costs			630				482
Non-cash compensation			2,665				2,264
(Gain) loss on disposal of assets			1,339				(584	)
Deferred income taxes			(31,507	)			7,666
Changes in operating assets and liabilities, net of acquisitions:
Accounts receivable			73,385				(23,934	)
Inventories			658				402
Prepaid expenses and other current assets			3,380				5,177
Other assets			(219	)			(198	)
Accounts payable			(10,507	)			991
Excess tax expense (benefit) from exercise of employee stock options / vesting of restricted stock			317				(1,583	)
Income tax payable			(24,213	)			1,015
Other liabilities			(243	)			(3,414	)
Accrued expenses			(8,370	)			4,331
Net cash provided by operating activities			73,049				87,328
Cash flows from investing activities:
Purchase of property and equipment			(25,187	)			(45,023	)
Proceeds from sale of assets			1,912				6,470
Payments for other long-term assets			(995	)			(2,048	)
Payments for businesses, net of cash acquired			(1,190	)			(51,239	)
Net cash used in investing activities			(25,460	)			(91,840	)
Cash flows from financing activities:
Payments of debt			(15,475	)			(10,874	)
Purchase of treasury stock			(6,104	)			(1,149	)
Excess tax (expense) benefit from exercise of employee stock options / vesting of restricted stock			(317	)			1,583
Tax withholding from exercise of stock options			(5	)			(842	)
Exercise of employee stock options			37				1,637
Deferred loan costs and other financing activities			(2,556	)			—
Net cash used in financing activities			(24,420	)			(9,645	)
Net increase (decrease) in cash and equivalents			23,169				(14,157	)
Cash and cash equivalents — beginning of period			111,135				91,941
Cash and cash equivalents — end of period		$	134,304			$	77,784

See accompanying notes to consolidated financial statements.

BASIC ENERGY SERVICES, INC.
Notes to Consolidated Financial Statements
June 30, 2009 (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 obligations

Revenue Recognition

     Well Servicing — Well servicing consists primarily of maintenance services, workover services, completion services and plugging and abandonment services. Basic recognizes revenue when services are performed, collection of the relevant receivables is probable, persuasive evidence of an arrangement exists and the price is fixed or determinable. Basic prices well servicing by the hour 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, nitrogen units, coiled tubing units, 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 and drill bits are stated at the lower of cost or market, with 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.

Property and Equipment

     Property and equipment are stated at cost or at estimated fair value at acquisition date if acquired in a business combination. Expenditures for repairs and maintenance are charged to expense as incurred and additions and improvements that significantly extend the lives of the assets are capitalized. Upon sale or other retirement of depreciable property, the cost and accumulated depreciation and amortization are removed from the related accounts and any gain or loss is reflected in operations. All property and equipment are depreciated or amortized (to the extent of estimated salvage values) on the straight-line method. The components of a well servicing rig generally require replacement or refurbishment during the well servicing rig’s life and are depreciated over their estimated useful lives, which ranges from 3 to 15 years. The costs of the original components of a purchased or acquired well servicing rig are not maintained separately from the base rig.

Impairments

     In accordance with Statement of Financial Accounting Standards (“SFAS”) 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.

     Basic’s goodwill is considered to have an indefinite useful economic life and is not amortized. Basic assesses impairment of its goodwill annually as of December 31 or on an interim basis if events or circumstances indicate that the fair value of the asset has decreased below its carrying value. SFAS No. 142, “Goodwill and Other Intangible Assets” (“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.

     In accordance with SFAS No. 142, the Company performed an assessment of goodwill as of March 31, 2009. A “triggering event” requiring this assessment was deemed to occur because the oil and gas services industry continued to decline in the first quarter and the Company’s common stock price declined by 50% from December 31, 2008 to March 31, 2009. For SFAS No. 142 Step One testing purposes, the Company tested three reporting units for goodwill impairment: well servicing, fluid services, and completion and remedial services. The Company’s contract drilling reporting unit does not carry any goodwill, and is not subject to the test.

     To estimate the fair value of the reporting units, the Company used a weighting of the discounted cash flow method and the public company guideline method of determining fair value of a business unit. The Company weighted the discounted cash flow method 85% and public company guideline method 15%, due to differences between the Company’s reporting units and the peer companies’ size, profitability and diversity of operations. In order to validate the reasonableness of the estimated fair values obtained for the reporting units, a reconciliation of fair value to market capitalization was performed for each unit on a stand-alone basis. A control premium, derived from market transaction data, was used in this reconciliation to ensure that fair values were reasonably stated in conjunction with the Company’s capitalization. The measurement date for the Company’s common stock price and market capitalization was the closing price on March 31, 2009.

     Based on the results of SFAS No. 142 Step One, impairment was indicated in all three of the assessed reporting units. As such, the Company was required to perform Step Two assessment on all three of the reporting units. Step Two requires the allocation of the estimated fair value to the tangible and intangible assets and liabilities of the respective unit. This assessment indicated that $204.1 million was considered impaired as of March 31, 2009. This non-cash charge eliminated all of the Company’s goodwill.

     Additionally, in accordance with SFAS No. 144, the Company performed an assessment of the Company’s long-lived assets for impairment. This assessment is performed as a comparison of the undiscounted future cash flows of each reporting unit to the carrying value of the assets in each unit. No impairment was indicated by this test.

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 amortized to interest expense using the effective interest method.

     Deferred debt costs were approximately $10.1 million net of accumulated amortization of $3.1 million and $7.6 million net of accumulated amortization of $2.4 million at June 30, 2009 and December 31, 2008, respectively. Amortization of deferred debt costs totaled approximately $391,000 and $242,000 for the three months ended June 30, 2009 and 2008, respectively. For the six months ended June 30, 2009 and 2008, amortization of deferred debt costs totaled approximately $630,000 and $482,000, respectively.

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. 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.

     As of June 30, 2009, Basic had no goodwill. All of the Company’s goodwill was considered impaired as of March 31, 2009.

     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 $35.4 million as of June 30, 2009 and December 31, 2008. The gross carrying amount of non-compete agreements subject to amortization totaled approximately $4.2 million and $4.4 million at June 30, 2009 and December 31, 2008, respectively. Accumulated amortization related to these intangible assets totaled approximately $5.3 million and $3.8 million at June 30, 2009 and December 31, 2008, respectively. Amortization expense for the three months ended June 30, 2009 and 2008 was approximately $803,000 and $636,000, respectively. Amortization expense for the six months ended June 30, 2009 and 2008 was approximately $1.6 million and $1.3 million, respectively Other intangibles net of accumulated amortization allocated to reporting units as of June 30, 2009 were $376,000, $3.1 million, $25.2 million and $5.7 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 SFAS 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 Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees” (“APB No. 25”).

     Basic accounts for income taxes based upon SFAS 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.

     Basic recognized an effective tax benefit rate of 22% in the first six months of 2009 compared to a tax rate of 38% in the first six months of 2008. The lower effective tax rate in the first six months of 2009 was primarily due to the $204.0 million goodwill impairment charge. The tax deductibility of the impairment charge was determined by the taxable basis of the goodwill considered to be impaired. A portion of the Company’s goodwill was not tax-deductible.

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

     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. Basic 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 three months ended June 30, 2009 or 2008.

     As of January 1, 2003, Basic adopted SFAS 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.

Environmental

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

Litigation and Self-Insured Risk Reserves

     Basic estimates its reserves related to litigation and self-insured risks based on the facts and circumstances specific to the litigation and self-insured claims and its past experience with similar claims in accordance with SFAS 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 Financial Accounting Standards Board (“FASB”) issued SFAS No. 157, “Fair Value Measurements” (“SFAS No. 157”), which became effective for financial assets and liabilities of the Company on January 1, 2008 and became 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 No. 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 was adopted for non-financial assets and liabilities, including fair value measurements for asset impairments, goodwill and intangible asset impairments, purchase price allocations and asset retirement obligations on January 1, 2009. The adoption of this standard did not have any impact on the fair value of any of the Company’s financial assets or liabilities. For further information, see note 13.

     In December 2007, the FASB issued SFAS No. 141R, “Business Combinations” (“SFAS No. 141R”), which became 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 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 No. 141R in 2009 will vary acquisition by acquisition.

     In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements” (“SFAS No. 160”), which became 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. This pronouncement has not had a significant impact on the Company’s results of operation or consolidated financial position since the Company does not have any noncontrolling interests.

     In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities” (“SFAS No. 161”), which became 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 a company’s financial position, financial performance and cash flows. This pronouncement did not have any impact on the Company’s results of operation or consolidated financial position since the Company does not have any derivative instruments.

     In April 2008, the FASB issued FASB Staff Position SFAS No. 142-3, “Determination of Useful Life of Intangible Assets” (“FSP No. 142-3”). FSP No. 142-3 amends the factors that should be considered in developing the renewal or extension assumptions used to determine the useful life of a recognized intangible asset under SFAS No. 142. FSP No. 142-3 is effective for fiscal years beginning after December 15, 2008. This pronouncement has not had a significant impact on the results of operation or consolidated financial position of the Company.

     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. FSP EITF 03-6-1 has not had a significant impact on the Company’s results of operation or consolidated financial position since the Company does not have any participating securities.

     In May 2009, the FASB issued SFAS No. 165, “Subsequent Events” (“SFAS No. 165”), which became effective for the Company on April 1, 2009. This standard establishes principles and requirements for disclosure of subsequent events. It establishes the period after the balance sheet date during which events or transactions are to be evaluated for potential disclosure. It also establishes the circumstances under which an entity shall recognize events or transactions occurring after the balance sheet date. The adoption of this standard requires the Company to disclose the date through which subsequent events have been reviewed.

     In June 2009, the FASB issued SFAS No. 168, “The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles, a replacement of FASB Statement no. 162” (“SFAS No. 168”), which becomes effective for the Company on July 1, 2009. SFAS No. 168 establishes the FASB Accounting Standards Codification as the source of authoritative accounting principles recognized by the FASB to be applied by nongovernmental entities in the preparation of financial statements in conformity with GAAP. SFAS No. 168 is not expected to change GAAP and will not have a material impact on the Company’s consolidated financial statements.

3. Acquisitions

     In the first six months of 2009 Basic did not acquire any businesses. In 2008, Basic acquired either substantially all of the assets or all of the outstanding capital stock of each of the following businesses, each of which was accounted for using the purchase method of accounting (in thousands):

				Total Cash Paid (net of
		Closing Date		cash acquired)
Xterra Fishing and Rental Tools Co.		January 28, 2008		$	21,473
Lackey Construction, LLC		January 30, 2008			4,328
B&S Disposal, LLC and B&S Equipment, Ltd		April 30, 2008			7,071
Triple N Services, Inc.		May 27, 2008			17,315
Azurite Services Company, Inc., Azurite Leasing Company, LLC and Freestone Disposal, L.P. (collectively, “Azurite”)		September 26, 2008			60,977
Total 2008				$	111,164

     The operations of each of the acquisitions listed above are included in Basic’s statement of operations as of each respective closing date. The acquisition of Azurite in 2008 has been deemed material and is 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.

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 $61.0 million in cash. This acquisition operates in our fluid services line of business and expands 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		$	53,127
Intangible Assets (1)			1,862
Goodwill (2)			5,988
Total Assets Acquired		$	60,977

     The following unaudited pro forma results of operations have been prepared as though the Azurite acquisition had been completed on January 1, 2008. 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).

		Six Months Ended
		June 30, 2008
Revenues		$	504,149
Net income		$	40,020
Earnings per common share — basic		$	0.98
Earnings per common share — diluted		$	0.96

     Basic does not believe the pro forma effect of the remainder of the acquisitions completed in 2008 are material, either individually or when aggregated, to the reported results of operations.

4. Property and Equipment

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

		June 30,				December 31,
		2009				2008
Land		$	5,275			$	4,689
Buildings and improvements			31,913				29,913
Well service units and equipment			385,750				379,167
Fluid services equipment			138,671				136,814
Brine and fresh water stations			10,443				10,203
Frac/test tanks			117,514				128,845
Pressure pumping equipment			169,636				156,406
Construction equipment			25,475				22,483
Contract drilling equipment			60,467				60,340
Disposal facilities			55,566				49,878
Vehicles			39,998				41,129
Rental equipment			37,317				36,898
Aircraft			4,119				4,119
Other			29,350				21,758
			1,111,494				1,082,642
Less accumulated depreciation and amortization			396,934				341,763
Property and equipment, net		$	714,560			$	740,879

     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 consisted of the following (in thousands):

		June 30,				December 31,
		2009				2008
Light vehicles		$	26,572			$	30,141
Well service units and equipment			1,713				1,194
Fluid services equipment			56,516				56,010
Pressure pumping equipment			27,276				20,492
Construction equipment			1,034				3,679
Software			13,659				9,464
Other			—				705
			126,770				121,685
Less accumulated amortization			38,018				37,370
		$	88,752			$	84,315

     Amortization of assets held under capital leases of approximately $5.1 million and $3.2 million for the three months ended June 30, 2009 and 2008 and $10.1 million and $6.6 million for the six months ended June 30, 2009 and 2008, respectively, is included in depreciation and amortization expense in the consolidated statements of operations.

5. Long-Term Debt

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

		June 30,				December 31,
		2009				2008
Credit Facilities:
Revolver		$	180,000			$	180,000
7.125% Senior Notes			225,000				225,000
Capital leases and other notes			75,274				75,323
			480,274				480,323
Less current portion			28,316				26,063
		$	451,958			$	454,260

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. 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 the Senior Notes, 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.

     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 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 June 30, 2009. In the event of a default on the Credit Facility 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.

     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.

Credit Facility

     On May 4, 2009, Basic entered into Amendment and Consent No. 1 (the “Amendment”) to its Fourth Amended and Restated Credit Agreement, dated February 6, 2007 (the “Existing Credit Agreement,” and as amended by the Amendment, the “Credit Facility”).

     Under the Credit Facility, Basic Energy Services, Inc. is the sole borrower and each of our subsidiaries is a subsidiary guarantor. The Credit Facility provides for an aggregate $225 million revolving line of credit (the “Revolver”). The Credit Facility includes provisions allowing Basic to request an increase in commitments of up to $100.0 million aggregate principal amount subject to

meeting certain tangible value requirements and subject to lender participation at the time of the request. 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.

     Under the Credit Facility, certain revolving loans are reclassified as (i) Tranche A Revolving Loans, which have the same maturity date as that of revolving loans under the Existing Credit Agreement (December 15, 2010), and (ii) Tranche B Revolving Loans, which have an extended maturity date of January 31, 2012. Revolving lenders are reclassified into two groups: those who agreed to extend the maturity date for their revolving commitments are deemed Tranche B Revolving Lenders, and the other revolving lenders are deemed Tranche A Revolving Lenders. The amount of commitments under the Tranche A Revolving Loans is $80 million and the amount under the Tranche B Revolving Loans is $145 million.

     For Tranche A Revolving Loans and Tranche B Revolving Loans, Alternative Base Rate loans (“ABR Loans”) bear interest at the highest of (i) the bank’s prime rate, (ii) the federal funds rate plus 0.50% per year, and (iii) the adjusted LIBOR rate for an interest period of one month beginning on the day of the ABR Loan plus 100 basis points, plus an applicable margin. The applicable margin for ABR Loans ranges from 0.25% to 0.50% for Tranche A Revolving Loans and ranges from 2.50% to 3.50% for Tranche B Revolving Loans. The applicable margin for Eurodollar revolving loans with respect to any Tranche B Revolving Loan ranges from 3.50% to 4.50%. Furthermore, the applicable commitment fee for the unused portion of any Tranche B revolving commitments, based on average daily unused amounts, is 1.0% per annum, as compared to 0.375% per annum for Tranche A revolving commitments.

     At June 30, 2009, Basic had $180.0 million of borrowings, and $16.2 million of letters of credit and no swing-line loans outstanding under the Revolver and remaining availabilty of $28.8 million.

     Pursuant to the Credit Facility, Basic must apply proceeds from certain specified events to reduce principal outstanding borrowings under the Revolver, including (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 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 3.75 to 1.00 on the effective date of the Amendment and thereafter, and (2) a minimum interest coverage ratio of 3.00 to 1.00. At June 30, 2009, Basic was in compliance with its covenants.

Other Debt

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

     See note 14 for discussion of secured senior notes offering.

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

		Six Months Ended June 30,
		2009				2008
Cash payments for interest		$	12,263			$	12,935
Commitment and other fees paid			157				51
Amortization of debt issuance costs			630				482
Change in accrued interest			(1,345	)			51
Other			5				283
		$	11,710			$	13,802

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 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 $250,000, 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.

     At June 30, 2009 and December 31, 2008, self-insured risk accruals for medical and dental coverage totaled approximately $14.6 million net of a $49,000 receivable and $15.4 million net of a $992,000 receivable, respectively.

7. Stockholders’ Equity

Common Stock

     At June 30, 2009 and December 31, 2008, Basic had 80,000,000 shares of common stock, par value $.01 per share, authorized.

     During the year ended December 31, 2008, Basic issued 447,255 shares of newly-issued common stock and 138,675 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. In October 2008, Basic granted a vice president 5,000 shares of restricted common stock which vest over a three year period.

     In March 2008, the Compensation Committee of Basic’s Board of Directors approved grants of performance-based stock awards to certain members of management. In March 2009, it was determined that 93,500 shares, or 100% of the target number of shares, were earned based on the Company’s achievement of certain earnings per share growth and 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. These shares remain subject to vesting over a three-year period, with the first shares vesting on March 15, 2010.

     In March 2009, Basic granted various employees 571,824 unvested shares of common stock which vest over a five-year period. Also, in March 2009, Basic granted the Chairman of the Board 4,000 shares of common stock which vested immediately in lieu of annual cash director fees.

     In May 2009, consistent with its director compensation practices, Basic granted a new board member 37,500 shares of restricted common stock which vest over a three-year period.

     During the six months ended June 30, 2009, Basic issued 5,000 shares of common stock from treasury stock for the exercise of stock options.

Treasury Stock

     On October 13, 2008, Basic announced that its Board of Directors authorized the repurchase of up to $50.0 million of Basic’s shares of common stock from time to time in open market or private transactions, at Basic’s discretion. The number of shares purchased and the timing of purchases are based on several factors, including the price of the common stock, general market conditions, available cash and alternative investment opportunities. During the year ended December 31, 2008, Basic repurchased 897,558 shares at a total price of $8.8 million (an average of $9.82 per share), inclusive of commissions and fees. During the first six months of 2009, Basic repurchased 809,093 shares at a total price of $6.0 million (an average of $7.41 per share), inclusive of commissions and fees.

     Basic also acquired treasury shares through net share settlements for payment of payroll taxes upon the vesting of restricted stock. Basic acquired a total of 52,877 shares through net share settlements during 2008 and 13,719 shares through net share settlements during the first six months of 2009.

Preferred Stock

     At June 30, 2009 and December 31, 2008, Basic had 5,000,000 shares of preferred stock, par value $.01 per share, authorized, of which none was designated, issued or outstanding.

8. Incentive Plan

     In May 2003, Basic’s board of directors and stockholders approved the Basic 2003 Incentive Plan (as amended effective May 26, 2009) (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 7,100,000 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.

     The fair value of each option award is estimated on the date of grant using the Black-Scholes-Merton option-pricing model. Basic is required to estimate the expected forfeiture rate and only recognize expense for those options expected to vest. During the three months ended June 30, 2009 and 2008, compensation expense related to share-based arrangements was approximately $1.3 million and $1.2 million, respectively. For compensation expense recognized during the three months ended June 30, 2009 and 2008, Basic recognized a tax benefit of approximately $509,000 and $453,000 respectively. During the six months ended June 30, 2009 and 2008, compensation expense related to share-based arrangements was approximately $2.7 million and $2.3 million, respectively. For compensation expense recognized during the six months ended June 30, 2009 and 2008, Basic recognized a tax benefit of approximately $992,000 and $857,000 respectively.

     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 June 30, 2009 and the changes during the six 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			1,608,675			$	11.11
Options granted			—
Options forfeited			(15,500	)		$	14.03
Options exercised			(5,000	)		$	6.98
Options expired			(91,250	)		$	6.05
Outstanding, end of period			1,496,925			$	11.40				5.34			$	1,424
Exercisable, end of period			1,124,050			$	9.18				4.96			$	1,424
Vested or expected to vest, end of period			1,483,175			$	11.27				5.32			$	1,424

     The total intrinsic value of share options exercised during the six months ended June 30, 2009 and 2008 was approximately $15,000 and $2.6 million, respectively.

     On March 13, 2009, the Compensation Committee of Basic’s Board of Directors approved grants of performance-based stock awards to certain members of management. The performance-based awards are tied to the Company’s achievement of certain earnings per share growth and return on capital employed performance over the performance period from January 1, 2007 through December 31, 2009, 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 265,000 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, 2011. As of June 30, 2009 it was estimated that none of the performance based awards will be earned.

     A summary of the status of the Company’s non-vested share grants at June 30, 2009 and changes during the six months ended June 30, 2009 is presented in the following table:

						Weighted Average
		Number of				Grant Date Fair
Nonvested Shares		Shares				Value Per Share
Nonvested at beginning of period			599,325			$	21.41
Granted during period			616,324				6.50
Vested during period			(72,375	)			20.04
Forfeited during period			(39,600	)			16.86
Performance based earned (1)			14,025				21.17
Nonvested at end of period			1,117,699			$	13.44

     As of June 30, 2009, there was approximately $12.6 million of total unrecognized compensation related to non-vested share-based compensation arrangements granted under the Plan. That cost is expected to be recognized over a weighted-average period of 3.29 years. The total fair value of share-based awards vested during the six months ended June 30, 2009 and 2008 was approximately $3.9 million and $10.0 million, respectively. The actual tax benefit realized for the tax deduction from vested share-based awards was $149,000 and $861,000 for the six months ended June 30, 2009 and 2008, respectively.

     Cash received from share option exercises under the Plan was approximately $35,000 and $795,000 for the six months ended June 30, 2009 and 2008, respectively. The actual tax benefit realized for the tax deductions from options exercised was $6,000 and $1.0 million for the six months ended June 30, 2009 and 2008, 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 $138,000 and $148,000 as of June 30, 2009 and December 31, 2008, 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.

10. Earnings Per Share

     Basic presents earnings per share information in accordance with the provisions of SFAS 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 June 30,								Six Months Ended June 30,
		2009				2008				2009				2008
		(Unaudited)								(Unaudited)
Numerator (both basic and diluted):
Net income (loss)		$	(21,236	)		$	18,713			$	(204,061	)		$	38,369
Denominator:
Denominator for basic earnings per share			39,574,561				40,721,317				39,773,857				40,649,287
Stock options			—				827,164				—				810,916
Unvested restricted stock			—				110,114				—				197,915
Denominator for diluted earnings per share			39,574,561				41,658,595				39,773,857				41,658,118
Basic earnings per common share:		$	(0.54	)		$	0.46			$	(5.13	)		$	0.94
Diluted earnings per common share:		$	(0.54	)		$	0.45			$	(5.13	)		$	0.92

     Stock options and unvested restricted stock shares of approximately 409,000 and 443,000 were excluded in the computation of diluted earnings per share for the three months and six months ended June 30, 2009, respectively as the effect would have been anti-dilutive due to the net loss in each of these periods.

11. Business Segment Information

     Basic’s reportable business segments are Well Servicing, Fluid Services, Completion and Remedial Services, and Contract Drilling. 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. Well servicing equipment and capabilities such as Basic’s 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, coiled tubing 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.

     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 June 30, 2009 (Unaudited)
Operating revenues		$	36,399			$	49,088			$	29,373			$	3,988			$	—			$	118,848
Direct operating costs			(27,825	)			(35,381	)			(21,484	)			(3,338	)			—			$	(88,028	)
Segment profits		$	8,574			$	13,707			$	7,889			$	650			$	—			$	30,820
Depreciation and amortization		$	12,127			$	9,131			$	7,653			$	1,803			$	1,699			$	32,413
Capital expenditures, (excluding acquisitions)		$	4,266			$	3,212			$	2,693			$	634			$	598			$	11,403
Three Months Ended June 30, 2008 (Unaudited)
Operating revenues		$	89,018			$	72,581			$	79,579			$	10,344			$	—			$	251,522
Direct operating costs			(55,293	)			(48,554	)			(42,651	)			(7,529	)			—				(154,027	)
Segment profits		$	33,725			$	24,027			$	36,928			$	2,815			$	—			$	97,495
Depreciation and amortization		$	11,492			$	7,046			$	7,041			$	1,853			$	1,300			$	28,732
Capital expenditures, (excluding acquisitions)		$	10,638			$	6,522			$	6,518			$	1,715			$	1,203			$	26,596
Six Months Ended June 30, 2009 (Unaudited)
Operating revenues		$	85,213			$	114,065			$	66,632			$	7,626			$	—			$	273,536
Direct operating costs			(64,742	)			(79,968	)			(47,378	)			(6,607	)			—			$	(198,695	)
Segment profits		$	20,471			$	34,097			$	19,254			$	1,019			$	—			$	74,841
Depreciation and amortization		$	24,375			$	18,353			$	15,383			$	3,624			$	3,415			$	65,150
Capital expenditures, (excluding acquisitions)		$	9,423			$	7,095			$	5,947			$	1,401			$	1,321			$	25,187
Identifiable assets		$	268,207			$	205,577			$	202,563			$	44,544			$	347,502			$	1,068,393
Six Months Ended June 30, 2008 (Unaudited)
Operating revenues		$	169,537			$	143,980			$	148,037			$	19,841			$	—			$	481,395
Direct operating costs			(103,759	)			(94,987	)			(78,439	)			(14,589	)			—				(291,774	)
Segment profits		$	65,778			$	48,993			$	69,598			$	5,252			$	—			$	189,621
Depreciation and amortization		$	22,704			$	13,921			$	13,911			$	3,661			$	2,567			$	56,764
Capital expenditures, (excluding acquisitions)		$	18,008			$	11,041			$	11,033			$	2,904			$	2,037			$	45,023
Identifiable assets		$	301,669			$	209,397			$	322,623			$	70,984			$	305,103			$	1,209,776

     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 June 30,								Six Months Ended June 30,
		2009				2008				2009				2008
Segment profits		$	30,820			$	97,495			$	74,841			$	189,621
General and administrative expenses			(27,424	)			(26,811	)			(56,503	)			(52,663	)
Depreciation and amortization			(32,413	)			(28,732	)			(65,150	)			(56,764	)
Loss on disposal of assets			(474	)			809				(1,339	)			584
Goodwill impairment			82				—				(204,014	)			—
Operating income (loss)		$	(29,409	)		$	42,761			$	(252,165	)		$	80,778

12. Supplemental Schedule of Cash Flow Information

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

		Six Months Ended June 30,
		2009				2008
		(In thousands)
Capital leases issued for equipment		$	15,426			$	20,522
Contingent earnout accrual		$	909			$	1,158
Asset retirement obligation additions		$	12			$	34

     Basic paid no income taxes during the six months ended June 30, 2009. Basic paid income taxes of approximately $13.2 million during the six months ended June 30, 2008. Basic paid interest of approximately $12.3 million and $12.9 million during the six months ended June 30, 2009 and 2008, respectively.

13. Fair Value Measurements

     SFAS No. 157 was issued by the FASB in September 2006 and became effective for financial assets and liabilities of the Company on January 1, 2008 and became effective for non-financial assets and liabilities of the Company on January 1, 2009. SFAS No. 157 defines fair value, establishes a framework for measuring fair value under GAAP and expands disclosures about fair value measurements. Fair value is the price that would be received to sell an asset or the amount paid to transfer a liability in an orderly transaction between market participants (an exit price) at the measurement date. Fair value is a market based measurement considered from the perspective of a market participant. The Company uses market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation. These inputs can be readily observable, market corroborated, or unobservable. If observable prices or inputs are not available, unobservable prices or inputs are used to estimate the current fair value, often using an internal valuation model. These valuation techniques involve some level of management estimation and judgment, the degree of which is dependent on the item being valued. The Company primarily applies a market approach for recurring fair value measurements using the best available information while utilizing valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs.

     SFAS No. 157 establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The Company classifies fair value balances based on the observability of those inputs. The three levels of the fair value hierarchy are as follows:

Level 1—Quoted prices in active markets for identical assets or liabilities that the Company has the ability to access. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

Level 2—Inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable. These inputs are either directly observable in the marketplace or indirectly observable through corroboration with market data for substantially the full contractual term of the asset or liability being measured.

Level 3—Inputs reflect management’s best estimate of what market participants would use in pricing the asset or liability at the measurement date. Consideration is given to the risk inherent in the valuation technique and the risk inherent in the inputs to the model.

     In valuing certain assets and liabilities, the inputs used to measure fair value may fall into different levels of the fair value hierarchy. For disclosure purposes, assets and liabilities are classified in their entirety in the fair value hierarchy level based on the lowest level of input that is significant to the overall fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement within the fair value hierarchy levels.

     The Company’s asset retirement obligation related to its 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, is measured using primarily Level 3 inputs. The

significant unobservable inputs to this fair value measurement include estimates of plugging, abandonment and remediation costs, inflation rate and well life. The inputs are calculated based on historical data as well as current estimated costs. The fair value is calculated by taking the present value of the expected cash flow at the time of the closure of the site. The following table reflects the changes in the fair value of the liability during the six months ended June 30, 2009 (in thousands):

		Asset
		Retirement
		Obligation
Balance, December 31, 2008		$	1,796
Additional asset retirement obligation			12
Accretion expense			73
Balance, June 30, 2009		$	1,881

14. Subsequent Events

     Management performed an evaluation of the Company’s activity through July 31, 2009, the date these financial statements were issued, noting the following subsequent event.

     On July 23, 2009, we announced that we had priced a private offering of $225 million of Senior Secured Notes due 2014, which will bear interest at a rate of 11.625% per annum. The notes are being sold at 94.621% of their face amount. We closed the sale of the notes July 31, 2009, and used the net proceeds from the offering to repay all outstanding indebtedness under our revolving credit facility.

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 purchased businesses and assets in 40 separate acquisitions from January 1, 2004 to June 30, 2009. Our weighted average number of well servicing rigs increased from 279 in 2004 to 414 in the second quarter of 2009 and our weighted average number of fluid service trucks increased from 386 to 808 in the same period. These acquisitions make our 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):

		Six Months Ended June 30,
		2009							2008
Revenues:
Well servicing		$	85.2				31	%		$	169.5				35	%
Fluid services			114.1				42	%			144.0				30	%
Completion and remedial services			66.6				24	%			148.0				31	%
Contract drilling			7.6				3	%			19.8				4	%
Total revenues		$	273.5				100	%		$	481.3				100	%

     Our core businesses depend on our customers’ willingness to make expenditures to produce, develop and explore for oil and gas in the United States. Industry conditions are influenced by numerous factors, such as the supply of and demand for oil and gas, domestic and worldwide economic conditions, political instability in oil producing countries and merger and divestiture activity among oil and gas producers. The volatility of the oil and gas industry, and the consequent impact on exploration and production activity, could adversely impact the level of drilling and workover activity by some of our customers. This volatility affects the demand for our services and the price of our services.

     In 2007, natural gas prices declined as an excess supply of natural gas began to develop, 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. By the middle of 2008, oil and natural gas prices reached historic highs. However, in the second half of 2008, oil and natural gas prices decreased substantially, which caused significantly lower utilization of our services in the fourth quarter of 2008. In the first half of 2009, utilization and pricing for our services continued to decline from the fourth quarter of 2008. For the second half of 2009, we expect oil and gas prices to remain below the levels required to support aggressive capital spending programs by our customers and that their maintenance related spending will be deferred for as long as possible. The reduced spending by our customers in the first half of 2009 is expected to continue in the second half of 2009, which will result in decreased demand for our services and increased competition among the service providers in each of our segments. We anticipate that utilization, revenue and margins in 2009 will be substantially below 2008 levels.

     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 fluctuate, demand for all of our services changes correspondingly as our customers must balance maintenance and capital expenditures against their available cash flows. 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. Adverse changes in capital markets have caused a number of oil and gas producers to reduce their capital budgets for the remainder of 2009. 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 return to historically high levels.

     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 will continue to evaluate opportunities to grow our business through selective acquisitions and internal growth initiatives. 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 2008 Acquisitions

     During the year 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 $21.5 million cash. This acquisition operates in our completion and remedial services line of business.

Azurite Services Company, Inc.

     On September 26, 2008, we acquired substantially all of the operating assets of Azurite for $61.0 million in cash. This acquisition operates in our fluid services line of business.

Segment Overview

Well Servicing

     During the first six months of 2009, our well servicing segment represented 31% 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 increased from a weighted average number of 392 rigs in the first quarter of 2008 to 414 in the second quarter of 2009 through a combination of newbuild purchases and acquisitions and other individual equipment purchases.

     The following is an analysis of our well servicing operations for each of the quarters in 2008, the full year ended December 31, 2008 and the quarters ended March 31, 2009 and June 30, 2009:

		Weighted
		Average								Rig								Profits
		Number of				Rig				Utilization				Revenue Per				Per Rig				Segment
		Rigs				Hours				Rate				Rig Hour				Hour				Profits%
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	%
Fourth Quarter			414				182,400				61.6	%		$	418			$	141				33.8	%
Full Year			405				840,200				72.5	%		$	408			$	152				37.3	%
2009:
First Quarter			414				132,300				44.7	%		$	369			$	90				24.4	%
Second Quarter			414				110,500				37.3	%		$	329			$	78				23.6	%

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

     Rig utilization declined to 37.3% in the second quarter of 2009 compared to 44.7% in the first quarter of 2009. The decline was caused by the continued slowdown in the economy and instability of oil prices experienced in the second quarter of 2009, which caused a decrease in demand for our services. This decrease was exacerbated by the continued weakness in natural gas prices. The decrease in demand for our services also caused price pressure, and our revenue per rig hour decreased to $329 in the second quarter of 2009 compared to $369 in the first quarter of 2009. Through our continued cost cutting measures, we were able to minimize the decrease in segment profit percentage to 23.6% in the second quarter of 2009 from 24.4% in the first quarter of 2009.

Fluid Services

     During the first six months of 2009, our fluid services segment represented 42% 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 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 in 2008, the full year ended December 31, 2008 and the quarters ended March 31, 2009 and June 30, 2009 (dollars in thousands):

		Weighted								Segment Profits
		Average Number of				Revenue Per				Per Fluid
		Fluid Service				Fluid Service				Service				Segment
		Trucks				Truck				Truck				Profits%
2008:
First Quarter			644			$	111			$	39				35.0	%
Second Quarter			663			$	109			$	36				33.1	%
Third Quarter			683			$	121			$	43				35.8	%
Fourth Quarter			804			$	111			$	42				38.1	%
Full Year			699			$	452			$	161				35.6	%
2009:
First Quarter			814			$	80			$	25				31.4	%
Second Quarter			808			$	61			$	17				27.9	%

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

     The decrease in revenue per fluid service truck to $61 in the second quarter of 2009 from $80 in the first quarter of 2009 and the decrease in segment profit percentage to 27.9% in the second quarter of 2009 from 31.4% in the first quarter of 2009 were caused by lower customer demand and rate decreases in all of our market areas.

Completion and Remedial Services

     During the first six months of 2009, our completion and remedial services segment represented 24% 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 lower-horsepower cementing, acidizing and fracturing services in selected markets. Our total hydraulic horsepower capacity for our pressure pumping operations was 139,000 and 128,000 at June 30, 2009 and June 30, 2008, 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.

     The following is an analysis of our completion and remedial services segment for each of the quarters in 2008, the full year ended December 31, 2008 and the quarters ended March 31, 2009 and June 30, 2009 (dollars in thousands):

						Segment
		Revenues				Profits%
2008:
First Quarter		$	68,458				47.7	%
Second Quarter		$	79,579				46.4	%
Third Quarter		$	85,541				45.3	%
Fourth Quarter		$	70,748				43.0	%
Full Year		$	304,326				45.6	%
2009:
First Quarter		$	37,259				30.5	%
Second Quarter		$	29,373				26.9	%

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

     The decrease in completion and remedial revenue to $29.4 million in the second quarter of 2009 from $37.3 million in the first quarter of 2009 was caused by the continued slowdown in the economy during the second quarter of 2009 along with natural gas prices remaining low, which resulted in lower demand for our services. Demand, particularly in our pressure pumping segment, and rates for our services decreased faster than our costs, resulting in the decrease in segment profit percentage to 26.9% in the second quarter of 2009 from 30.5% in the first quarter of 2009.

Contract Drilling

     During the first six months of 2009, our contract drilling segment represented 3% 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. 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 had a weighted average of nine rigs during the four quarters of 2008 and the first and second quarter of 2009.

     The following is an analysis of our contract drilling segment for each of the quarters in 2008, the full year ended December 31, 2008 and the quarters ended March 31, 2009 and June 30, 2009:

		Weighted
		Average				Rig
		Number of				Operating				Revenue				Profits				Segment
		Rigs				Days				Per Day				Per Day				Profits%
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	%
Fourth Quarter			9				666			$	14,900			$	5,400				36.2	%
Full Year			9				2,777			$	15,000			$	4,700				31.4	%
2009:
First Quarter			9				248			$	14,700			$	1,500				10.1	%
Second Quarter			9				314			$	12,700			$	2,100				16.3	%