Basic Energy Services 10Q 2011 Q2 Quarterly report

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q


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

For the quarterly period ended June 30, 2011


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

For the transition period from to

Commission File Number 001-32693

Basic Energy Services, Inc.

(Exact name of registrant as specified in its charter)


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

500 W. Illinois, Suite 100 Midland, Texas (Address of principal executive offices)		79701 (Zip code)

(432) 620-5500

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yesþ Noo

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). Yesþ Noo

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


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

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

42,428,030 shares of the registrant’s Common Stock were outstanding as of July 20, 2011.

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, 2011 (Unaudited) and December 31, 2010			4
Consolidated Statements of Operations and Comprehensive Income for the three months and six months ended June 30, 2011 and 2010 (Unaudited)			5
Consolidated Statements of Stockholders’ Equity for the six months ended June 30, 2011 (Unaudited)			6
Consolidated Statements of Cash Flows for the six months ended June 30, 2011 and 2010 (Unaudited)			7
Notes to the Unaudited 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			26
Operating Cost Overview			29
Critical Accounting Policies and Estimates			29
Results of Operations			31
Liquidity and Capital Resources			33
Other Matters			39
Item 3. Quantitative and Qualitative Disclosures About Market Risk			39
Item 4. Controls and Procedures			39
Part II. OTHER INFORMATION			40
Item 1. Legal Proceedings			40
Item 1A. Risk Factors			40
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			40
Item 6. Exhibits			41
Signatures			43

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 in our most recent annual report on Form 10-K and other factors, most of which are beyond our control.

The words “believe,” “may,” “estimate,” “continue,” “anticipate,” “intend,” “plan,” “expect,” “indicate” 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 natural 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,
	2011			2010
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	220,910		$	47,918
Trade accounts receivable, net of allowance of $1,997 and $3,078, respectively		200,092			150,364
Accounts receivable — related parties		44			42
Income tax receivable		78,195			79,480
Inventories		25,662			21,556
Prepaid expenses		6,334			5,425
Other current assets		6,632			18,193
Deferred tax assets		8,430			8,290

Total current assets		546,299			331,268

Property and equipment, net		693,891			625,702
Deferred debt costs, net of amortization		16,348			6,835
Goodwill		16,287			16,150
Other intangible assets, net of amortization		43,727			45,833
Other assets		12,555			4,025

Total assets	$	1,329,107		$	1,029,813

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	39,787		$	40,477
Accrued expenses		61,780			51,237
Current portion of long-term debt		27,816			24,231
Other current liabilities		166			3,309

Total current liabilities		129,549			119,254

Long-term debt, net of unamortized discount or premium on notes of $1,991 and $9,425, respectively		762,190			474,628
Deferred tax liabilities		117,636			123,393
Other long-term liabilities		11,369			10,615
Commitments and contingencies
Stockholders’ equity:
Preferred stock; $.01 par value; 5,000,000 shares authorized; none designated or issued at June 30, 2011 and December 31, 2010, respectively		—			—
Common stock; $.01 par value; 80,000,000 shares authorized; 42,432,309 shares issued, and 42,394,955 shares outstanding at June 30, 2011; 42,394,809 shares issued, and 41,310,447 shares outstanding at December 31, 2010.		424			424
Additional paid-in capital		343,385			335,927
Retained earnings (deficit)		(35,446	)		(27,544	)
Treasury stock, at cost, 37,354 and 1,084,362 shares at June 30, 2011 and December 31, 2010, respectively		—			(6,884	)

Total stockholders’ equity		308,363			301,923

Total liabilities and stockholders’ equity	$	1,329,107		$	1,029,813

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,
	2011			2010			2011			2010
	(Unaudited)						(Unaudited)
Revenues:
Completion and remedial services	$	121,807		$	61,533		$	219,314		$	106,767
Fluid services		81,415			58,801			153,760			110,948
Well servicing		83,881			49,529			153,028			91,325
Contract drilling		9,752			5,269			16,807			9,058


Total revenues		296,855			175,132			542,909			318,098


Expenses:
Completion and remedial services		68,827			37,660			123,760			67,383
Fluid services		51,688			43,425			99,916			84,365
Well servicing		57,409			36,734			105,849			68,834
Contract drilling		7,393			3,725			11,878			6,995
General and administrative, including stock-based compensation of $2,078 and $1,439 in three months ended June 30, 2011 and 2010, and $3,758 and $2,589 in the six months ended June 30, 2011 and 2010, respectively		34,138			26,820			65,479			51,897
Depreciation and amortization		34,784			34,250			67,764			67,348
(Gain) loss on disposal of assets		942			463			(763	)		1,174


Total expenses		255,181			183,077			473,883			347,996


Operating income (loss)		41,674			(7,945	)		69,026			(29,898	)

Other income (expense):
Interest expense		(11,842	)		(11,778	)		(23,184	)		(23,442	)
Interest income		23			24			28			50
Gain on bargain purchase		—			1,772			—			1,772
Loss on early extinguishment of debt		—			—			(49,366	)		—
Other income (expense)		102			111			259			192


Income (loss) from continuing operations before income taxes		29,957			(17,816	)		(3,237	)		(51,326	)

Income tax benefit (expense)		(13,407	)		7,144			1,294			19,063



Net income (loss)	$	16,550		$	(10,672	)	$	(1,943	)	$	(32,263	)


Earnings (loss) per share of common stock:
Basic	$	0.41		$	(0.27	)	$	(0.05	)	$	(0.81	)


Diluted	$	0.40		$	(0.27	)	$	(0.05	)	$	(0.81	)

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, 2010		42,394,809	$	424	$	335,927		$	(6,884	)	$	(27,544	)	$	301,923

Issuances of restricted stock		—		—		(32	)		5,783			(5,751	)		—
Amortization of share-based compensation		—		—		3,758			—			—			3,758
Purchase of treasury stock		—		—		—			(1,761	)		—			(1,761	)
Exercise of stock options / vesting of restricted stock		37,500		—		3,732			2,862			(208	)		6,386
Net loss		—		—		—			—			(1,943	)		(1,943	)

Balance — June 30, 2011 (unaudited)		42,432,309	$	424	$	343,385		$	—		$	(35,446	)	$	308,363

See accompanying notes to consolidated financial statements.

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


	Six Months Ended June 30,
	2011			2010
	(Unaudited)
Cash flows from operating activities:
Net loss	$	(1,943	)	$	(32,263	)
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		67,764			67,348
Gain on bargain purchase		—			(1,772	)
Accretion on asset retirement obligation		65			81
Change in allowance for doubtful accounts		(1,081	)		(953	)
Amortization of deferred financing costs		967			762
Amortization of discount on senior secured notes		6,484			937
Non-cash compensation		3,758			2,589
Loss on early extinguishment of debt (non-cash)		3,940			—
Premium on retirement of 11.625% senior secured notes		36,179			—
(Gain) loss on disposal of assets		(763	)		1,174
Deferred income taxes		(6,088	)		(3,311	)

Changes in operating assets and liabilities, net of acquisitions:

Accounts receivable		(48,744	)		(30,886	)
Inventories		(4,106	)		(1,439	)
Prepaid expenses and other current assets		(1,102	)		3,747
Other assets		(8,531	)		(2,981	)
Accounts payable		(690	)		3,379
Excess tax expense (benefit) from exercise of employee stock options / vesting of restricted stock		(3,508	)		360
Income tax payable		4,793			(15,460	)
Other liabilities		(2,328	)		1,587
Accrued expenses		10,515			5,505

Net cash provided by (used in) operating activities		55,581			(1,596	)

Cash flows from investing activities:
Purchase of property and equipment		(114,873	)		(25,555	)
Proceeds from sale of assets		17,996			1,787
Change in restricted cash		—			(1,124	)
Payments for other long-term assets		(287	)		(350	)
Payments for businesses, net of cash acquired		(10	)		(10,312	)

Net cash used in investing activities		(97,174	)		(35,554	)

Cash flows from financing activities:
Proceeds from debt		498,850			—
Payments of debt		(238,291	)		(13,805	)
Premium on retirement of 11.625% senior secured notes		(36,179	)		—
Purchase of treasury stock		(1,761	)		(316	)
Excess tax (expense) benefit from exercise of employee stock options / vesting of restricted stock		3,508			(360	)
Tax withholding from exercise of stock options		(2,529	)		(8	)
Exercise of employee stock options		5,407			65
Deferred loan costs and other financing activities		(14,420	)		(8	)

Net cash provided by (used in) financing activities		214,585			(14,432	)


Net increase (decrease) in cash and equivalents		172,992			(51,582	)

Cash and cash equivalents — beginning of period		47,918			125,357

Cash and cash equivalents — end of period	$	220,910		$	73,775

See accompanying notes to consolidated financial statements.

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements
June 30, 2011 (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 which are of a normal recurring nature considered necessary for a fair presentation have been made in the accompanying unaudited financial statements.

Nature of Operations

Basic provides a wide range of well site services to oil and natural gas drilling and producing companies, including completion and remedial services, fluid services and well site construction services, well servicing and contract drilling. These services are primarily provided using 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, Louisiana, Wyoming, North Dakota, Colorado, Utah, Montana, West Virginia, and Pennsylvania.

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 variable interest in any other organization, entity, partnership, or contract. 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

•

Future cash flows

•

Stock-based compensation

•

Income taxes

•

Asset retirement obligations

Revenue Recognition

Completion and Remedial Services —Completion and remedial services consists primarily of pumping services, focused on cementing, acidizing and fracturing, nitrogen units, coiled tubing units, snubbing 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 value of the services.

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.

Well Servicing— Well servicing consists primarily of maintenance services, workover services, completion services, plugging and abandonment services and rig manufacturing and servicing. 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. Rig manufacturing revenue is recognized when the rig is accepted by the customer, based on the completed contract method by individual rig.

Contract Drilling —Contract drilling consists primarily of drilling wells to a specified depth using drilling 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 by the average cost method. Other inventories, consisting mainly of manufacturing raw materials, 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 range 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

Long-lived assets, such as property, plant, and equipment, and purchased intangibles subject to amortization, are reviewed for impairment at least 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 and trade name intangibles are considered to have an indefinite useful economic life and are not amortized. Basic assesses impairment of its goodwill and trade name intangibles annually as of December 31 or on an interim basis if events or circumstances indicate that the fair value of the assets has decreased below the assets’ carrying value. A two-step process is required for testing impairment of goodwill. 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.

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 $19.6 million net of accumulated amortization of $3.3 million and $10.7 million net of accumulated amortization of $3.9 million at June 30, 2011 and December 31, 2010, respectively. Amortization of deferred debt costs totaled approximately $535,000 and $380,000 for the three months ended June 30, 2011 and 2010, respectively. Amortization of deferred debt costs totaled approximately $967,000 and $762,000 for the six months ended June 30, 2011 and 2010, respectively.

Basic recorded a charge of $3.9 million during the first quarter of 2011 related to the write-off of debt costs associated with its 11.625% Senior Secured Notes and $30.0 million revolving credit facility. On February 15, 2011, Basic terminated the revolving credit facility and completed the closing for an early tender for approximately $224.7 million of the Senior Secured Notes and delivered to the trustee amounts required to satisfy and discharge remaining obligations for the outstanding notes. Basic also incurred $2.9 million of deferred debt costs associated with the $165.0 million revolving credit facility entered into on February 15, 2011. Additionally, on June 13, 2011, Basic incurred $11.5 million of deferred debt costs associated with the issuance of additional 7.75% Senior Notes due 2019.

Goodwill and Other Intangible Assets

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 completes its assessment of goodwill and trade name intangible impairment December 31 of each year.

Basic had trade names of $1.8 million as of June 30, 2011 and December 31, 2010. Trade names have an indefinite life and are tested for impairment annually.

The changes in the carrying amount of goodwill for the six months ended June 30, 2011 are as follows (in thousands):


	Completion and
	Remedial			Fluid		Well		Contract
	Services			Services		Servicing		Drilling		Total
Balance as of December 31, 2010	$	10,771		$	488	$	4,891	$	—	$	16,150
Goodwill adjustments		(74	)		148		63		—		137

Balance as of June 30, 2011	$	10,697		$	636	$	4,954	$	—	$	16,287

Basic’s intangible assets subject to amortization consist of customer relationships, non-compete agreements and rig engineering plans. The gross carrying amount of customer relationships subject to amortization was $48.0 million at both June 30, 2011 and December 31, 2010. The gross carrying amount of non-compete agreements subject to amortization totaled approximately $4.3 million and $4.9 million at June 30, 2011 and December 31, 2010, respectively. The gross carrying amount of rig engineering plans subject to amortization was $746,000 at both June 30, 2011 and December 31, 2010. Accumulated amortization related to these intangible assets totaled approximately $11.1 million and $9.6 million at June 30, 2011 and December 31, 2010, respectively. Amortization expense for the three months ended June 30, 2011 and 2010 was approximately $1.0 million and $844,000, respectively. Amortization expense for the six months ended June 30, 2011 and 2010 was approximately $2.1 million and $1.7 million, respectively. Other intangibles net of accumulated amortization allocated to reporting units as of June 30, 2011 were $30.0 million,

$2.5 million, $4.6 million and $4.8 million for completion and remedial services, fluid services, well servicing, and contract drilling, respectively. No adjustments were made to prior periods to reflect subsequent adjustments to acquisitions due to immateriality.

Customer relationships are amortized over a 15-year life, non-compete agreements are amortized over a five-year life, and rig engineering plans are amortized over a 15-year life.

Stock-Based Compensation

Basic’s stock-based awards consist of stock options and restricted stock. Stock options issued are valued on the grant date using the Black-Scholes-Merton option-pricing model, and restricted stock issued is valued based on the fair value of Basic’s common stock at the grant date. All stock-based awards are adjusted for an expected forfeiture rate and amortized over the vesting period.

Income Taxes

Basic recognizes deferred tax assets and liabilities for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using statutory tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rate is recognized in the period that includes the statutory enactment date. A valuation allowance for deferred tax assets is recognized when it is more likely than not that the benefit of deferred tax assets will not be realized.

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

Concentrations of Credit Risk

Financial instruments, which potentially subject Basic to concentration of credit risk, consist primarily of temporary cash investments and trade receivables. Basic restricts investment of temporary cash investments to financial institutions with high credit standing. Basic’s customer base consists primarily of multi-national and independent oil and natural gas producers. 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 that represented 10% or more of consolidated revenue during the three months or six months ended June 30, 2011 or 2010.

Asset Retirement Obligations

Basic records 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 capitalizes 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, chemicals 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, its past experience with similar claims and the likelihood of the future event occurring. Basic maintains accruals on the consolidated balance sheets to cover self-insurance retentions (See note 6).

Recent Accounting Pronouncements

In January 2010, the FASB issued ASU No. 2010-06, “Improving Disclosures about Fair Value Measurements” (“ASU No. 2010-06”). ASU No. 2010-06 requires the disclosure of significant transfers in and out of Level 1 and Level 2 fair value measurements. It also requires that Level 3 fair value measurements present information about purchases, sales, issuances and settlements. Fair value disclosures should also disclose valuation techniques and inputs used to measure both recurring and nonrecurring fair value measurements. This update became effective for Basic on January 1, 2010 except for the disclosures about purchases, sales, issuances, and settlements in the roll forward in activity in Level 3 fair value measurements, which became effective on January 1, 2011. This update did not change the techniques Basic uses to measure fair value and has not had a material impact on its consolidated financial statements.

In December 2010, the FASB issued ASU No. 2010-09, “Business Combinations: Disclosure of Supplementary Pro Forma Information for Business Combinations”(“ASU 2010-29”). ASU 2010-29 addresses diversity in the interpretation of the pro forma revenue and earnings disclosure requirements for business combinations. If a public entity presents comparative financial statements, the entity should disclose revenue and earnings of the combined entity as though the business combination that occurred during the current year had occurred as of the beginning of the comparable prior annual reporting period only. The Company adopted ASU 2010-29 on January 1, 2011. This update had no impact on the Company’s financial position, results of operations or cash flows.

3. Acquisitions

In 2010, 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. The following table summarizes the provisional values at the date of acquisition (in thousands):


		Total Cash Paid (net of cash
	Closing Date	acquired)
Rocky Mountain Cementers, Inc.	March 1, 2010	$	687
New Tech Systems, Inc	April 20, 2010	$	900
Taylor Rig, LLC	May 3, 2010	$	8,734
Platinum Pressure Services, Inc. and Admiral Well Service, Inc.	December 16, 2010	$	39,942

Total 2010		$	50,263

The operations of each of the acquisitions listed above are included in Basic’s statement of operations as of each respective closing date. Basic does not believe the pro forma effect of any of the acquisitions completed in 2010 is material, either individually or when aggregated, to the reported results of operations.

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. For acquisitions that occurred prior to January 1, 2009, 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. For any acquisition that occurred after December 31, 2008, the contingent earn-out is measured at fair value at the date of acquisition and any adjustments to that fair value are recorded through the statement of operations.

4. Property and Equipment

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


	June 30,		December 31,
	2011		2010
Land	$	5,391	$	5,361
Buildings and improvements		35,310		32,047
Well service units and equipment		429,343		416,015
Fluid services equipment		159,073		148,989
Brine and fresh water stations		11,306		10,969
Frac/test tanks		183,611		151,379
Pressure pumping equipment		186,575		171,892
Construction equipment		28,571		27,799
Contract drilling equipment		76,281		44,181
Disposal facilities		70,129		66,388
Vehicles		44,645		39,844
Rental equipment		45,964		43,502
Aircraft		4,251		4,251
Software		22,248		22,296
Other		9,547		7,345

		1,312,245		1,192,258
Less accumulated depreciation and amortization		618,354		566,556

Property and equipment, net	$	693,891	$	625,702

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,
	2011		2010
Light vehicles	$	27,622	$	25,800
Well service units and equipment		1,536		1,791
Fluid services equipment		77,472		65,874
Pressure pumping equipment		22,352		18,293
Construction equipment		1,269		1,269
Software		15,548		15,548
Other		244		244

		146,043		128,819
Less accumulated amortization		58,793		56,087

	$	87,250	$	72,732

Amortization of assets held under capital leases of approximately $5.2 million and $5.9 million for the three months ended June 30, 2011 and 2010, respectively, and $10.2 million and $10.9 million for the six months ended June 30, 2011 and 2010, 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,
	2011		2010
Credit Facilities:
Revolver	$	21,850	$	—
7.125% Senior Notes		225,000		225,000
11.625% Senior Secured Notes		—		225,000
7.75% Senior Notes		475,000		—
Unamortized (discount) premium		1,991		(9,425	)
Capital leases and other notes		66,165		58,284

		790,006		498,859
Less current portion		27,816		24,231

	$	762,190	$	474,628

7.125% Senior Notes due 2016

On April 12, 2006, Basic issued $225.0 million of 7.125% Senior Notes due April 2016 (the “7.125% Senior Notes”) in a private placement. Proceeds from the sale of the 7.125% Senior Notes were used to retire the outstanding balance on Basic’s $90.0 million Term B Loan and to pay down approximately $96.0 million under Basic’s previous revolving credit facility. The 7.125% Senior Notes are unsecured. Under the terms of the sale of the 7.125% Senior Notes, Basic was required to take appropriate steps to offer to exchange other 7.125% Senior Notes with the same terms that have been registered with the Securities and Exchange Commission for the private placement 7.125% Senior Notes. Basic completed the exchange offer for all of the 7.125% Senior Notes on October 16, 2006.

Basic issued the 7.125% Senior Notes pursuant to an indenture, dated as of April 12, 2006, by and among Basic, the guarantor parties thereto and The Bank of New York Trust Company, N.A., as trustee (the “7.125% Senior Notes Indenture”). Interest on the 7.125% Senior Notes accrues at a rate of 7.125% per year. Interest payments on the 7.125% Senior Notes are due semi-annually, on April 15 and October 15.

The 7.125% Senior Notes are redeemable at the option of Basic on or after April 15, 2011 at the specified redemption price as described in the 7.125% Senior Notes Indenture.

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

The 7.125% Senior Notes Indenture contains covenants that, among other things, limit the ability of Basic and its restricted subsidiaries to incur additional indebtedness; pay dividends or repurchase or redeem capital stock; make certain investments; incur liens; enter into certain types of transactions with affiliates; limit dividends or other payments by restricted subsidiaries; and sell assets or consolidate or merge with or into other companies. These limitations are subject to a number of important qualifications and exceptions set forth in the 7.125% Senior Notes Indenture. At June 30, 2011, Basic was in compliance with the restrictive covenants under the 7.125% Senior Notes Indenture.

As part of the issuance of the above-mentioned 7.125% 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 7.125% Senior Notes.

The 7.125% Senior Notes are jointly and severally, and unconditionally, guaranteed on a senior unsecured basis by all of Basic’s current subsidiaries, other than three immaterial subsidiaries. As of June 30, 2011, these three subsidiaries held no assets and performed no operations. Basic Energy Services, Inc., the ultimate parent company, does not have any independent operating assets or operations.

7.75% Senior Notes due 2019

On February 15, 2011, Basic successfully completed the issuance and sale of $275.0 million and on June 13, 2011, Basic successfully completed the issuance and sale of an additional $200.0 million, for an aggregate principal amount of $475.0 million of 7.75% Senior Notes due 2019 (the “7.75% Senior Notes”). The 7.75% Senior Notes are jointly and severally, and unconditionally,

guaranteed on a senior unsecured basis by all of Basic’s current subsidiaries, other than three immaterial subsidiaries. The 7.75% Senior Notes and the guarantees rank (i) equally in right of payment with any of Basic’s and the subsidiary guarantors’ existing and future senior indebtedness, including Basic’s existing 7.125% Senior Notes and the related guarantees, and (ii) effectively junior to all existing or future liabilities of Basic’s subsidiaries that do not guarantee the 7.75% Senior Notes and to Basic’s and the subsidiary guarantors’ existing or future secured indebtedness to the extent of the value of the collateral therefore.

The 7.75% Senior Notes were offered and sold in private transactions in accordance with Rule 144A and Regulation S under the Securities Act of 1933, as amended (the “Securities Act”).

The purchase price for the $275.0 million of 7.75% Senior Notes issued on February 15, 2011 was 100.000% of their principal amount and the purchase price for the $200.0 million of 7.75% Senior Notes issued on June 13, 2011 was 101.000%, plus accrued interest from February 15, 2011. Basic received net proceeds from the issuance of the 7.75% Senior Notes of approximately $465.5 million after premiums and offering expenses. Basic used a portion of the net proceeds from the February 2011 offering to fund its tender offer and consent solicitation for its 11.625% Senior Secured Notes and to redeem any of the Senior Secured Notes not purchased in the tender offer. Basic also intends to use a portion of the net proceeds from the June 2011 offering to fund the $180.0 million purchase price for the Maverick companies acquisition completed in July 2011 and for general corporate purposes.

The 7.75% Senior Notes were issued pursuant to an indenture dated as of February 15, 2011 (the “7.75% Senior Notes Indenture”), by and among Basic, the guarantors party thereto and Wells Fargo Bank, N.A., as trustee . Interest on the 7.75% Senior Notes accrues from and including February 15, 2011 at a rate of 7.75% per year. Interest on the 7.75% Senior Notes is payable semi-annually in arrears on February 15 and August 15 of each year, commencing on August 15, 2011. The 7.75% Senior Notes mature on February 15, 2019.

The 7.75% Senior Notes Indenture contains covenants that, among other things, limit Basic’s ability and the ability of certain of its subsidiaries to: incur additional indebtedness; pay dividends or repurchase or redeem capital stock; make certain investments; incur liens; enter into certain types of transactions with its affiliates; limit dividends or other payments by Basic’s restricted subsidiaries to Basic; and sell assets or consolidate or merge with or into other companies. These and other covenants that are contained in the 7.75% Senior Notes Indenture are subject to important exceptions and qualifications set forth in the 7.75% Senior Notes Indenture. At June 30, 2011, Basic was in compliance with the restrictive covenants under the 7.75% Senior Notes Indenture.

Basic may, at its option, redeem all or part of the 7.75% Senior Notes, at any time on or after February 15, 2015, at a redemption price equal to 100% of the principal amount thereof, plus a premium declining ratably to par and accrued and unpaid interest to the date of redemption.

At any time before February 15, 2014, Basic, at its option, may redeem up to 35% of the aggregate principal amount of the 7.75% Senior Notes issued under the 7.75% Senior Notes Indenture with the net cash proceeds of one or more qualified equity offerings at a redemption price of 107.750% of the principal amount of the 7.75% Senior Notes to be redeemed, plus accrued and unpaid interest to the date of redemption, as long as:

•

at least 65% of the aggregate principal amount of the 7.75% Senior Notes issued under the 7.75% Senior Notes Indenture remains outstanding immediately after the occurrence of such redemption; and

•

such redemption occurs within 90 days of the date of the closing of any such qualified equity offering.

In addition, at any time before February 15, 2015, Basic may redeem some or all of the 7.75% Senior Notes at a redemption price equal to 100% of the principal amount of the 7.75% Senior Notes, plus an applicable premium and accrued and unpaid interest to the date of redemption.

Following a change of control, as defined in the 7.75% Senior Notes Indenture, Basic will be required to make an offer to repurchase all or a portion of the Notes at 101% of their principal amount, plus accrued and unpaid interest to the date of repurchase.

Revolving Credit Facility

On February 15, 2011, in connection with the 7.75% Senior Notes offering, Basic entered into a new $165.0 million revolving credit facility (the “Credit Agreement”) with Merrill Lynch, Pierce, Fenner & Smith Incorporated and Capital One, National Association, as joint lead arrangers and joint book managers, the lenders party thereto and Bank of America, N.A., as administrative agent. The Credit Agreement includes an accordion feature whereby the total credit available to Basic can be increased by up to $100.0 million under certain circumstances, subject to additional lender commitments. The obligations under the Credit Agreement are guaranteed on a joint and several basis by each of Basic’s current subsidiaries, other than three immaterial subsidiaries, and are secured by substantially all assets of Basic and the guarantors as collateral under a related Security Agreement (the “Security Agreement”). As of June 30, 2011, the non-guarantor subsidiaries held no assets and performed no operations.

Borrowings under the Credit Agreement mature on January 15, 2016, and Basic has the ability at any time to prepay the Credit Agreement without premium or penalty. At Basic’s option, advances under the Credit Agreement may be comprised of (i) alternate base rate loans, at a variable base interest rate plus a margin ranging from 1.50% to 2.25% based on Basic’s leverage ratio or (ii) Eurodollar loans, at a variable base interest rate plus a margin ranging from 2.50% to 3.25% based on Basic’s leverage ratio. Basic will pay a commitment fee equal to 0.50% on the daily unused amount of the commitments under the Credit Agreement.

The Credit Agreement contains various covenants that, subject to agreed upon exceptions, limit Basic’s ability and the ability of certain of Basic’s subsidiaries to:

•

incur indebtedness;

•

grant liens;

•

enter into sale and leaseback transactions;

•

make loans, capital expenditures, acquisitions and investments;

•

change the nature of business;

•

acquire or sell assets or consolidate or merge with or into other companies;

•

declare or pay dividends;

•

enter into transactions with affiliates;

•

enter into burdensome agreements;

•

prepay, redeem or modify or terminate other indebtedness;

•

change accounting policies and reporting practices; and

•

amend organizational documents.

The Credit Agreement also contains covenants that, among other things, limit the amount of capital contributions Basic may make and require Basic to maintain specified ratios or conditions as follows:

•

a minimum consolidated interest coverage ratio of not less than 2.50:1.00;

•

a maximum consolidated leverage ratio not to exceed:

•

4.25:1.00 for the quarter ending March 31, 2011; and

•

4.00:1.00 after March 31, 2011; and

•

a maximum consolidated senior secured leverage ratio of 2.00:1.00.

If an event of default occurs under the Credit Agreement, then the lenders may (i) terminate their commitments under the Credit Agreement, (ii) declare any outstanding loans under the Credit Agreement to be immediately due and payable after applicable grace periods and (iii) foreclose on the collateral secured by the Security Agreement.

Basic had $21.9 million outstanding under the Credit Agreement as of June 30, 2011. At June 30, 2011, Basic was in compliance with its covenants under the Credit Agreement.

Other Debt

Basic has a variety of other capital leases and notes payable outstanding that are generally customary in its business. None of these debt instruments are individually material. Basic’s leases with Banc of America Leasing & Capital, LLC require us to maintain a minimum debt service coverage ratio of 1.05 to 1.00. At June 30, 2011, Basic was in compliance with this covenant.

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


	Six Months Ended June 30,
	2011		2010
Cash payments for interest	$	18,630	$	21,802
Commitment and other fees paid		438		9
Amortization of debt issuance costs and discount or premium on notes		1,213		1,699
Change in accrued interest		2,871		(73	)
Other		32		5

	$	23,184	$	23,442

Losses on Extinguishment of Debt

In February 2011, upon the retirement of the 11.625% Senior Secured Notes and the termination of Basic’s $30.0 million revolving credit facility, Basic wrote off unamortized debt issuance costs of approximately $3.9 million and unamortized discount of $9.2 million. Basic also paid a premium of $36.2 million to the holders of the 11.625% Senior Secured Notes for the early termination of the notes.

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.

During April 2011, Basic and certain officers received notice from the Travis County District Attorney of a pending investigation of a potential felony criminal case referred by Texas Parks & Wildlife and the Texas Environmental Enforcement Task Force, to be presented to a Travis County grand jury. The potential matter relates to a land farm owned by Basic located in Jefferson County, Texas. While Basic is currently responding to additional inquiries regarding the investigation and believes the investigation may also relate to alleged unlawful discharges, Basic has not been informed of any specific potential charges at this time. Basic does not believe it is probable or reasonably possible that this matter will result in any material adverse effect on its financial condition, results of operations or liquidity; however, there can be no assurance as to the ultimate outcome of this matter.

Litigation

Self-Insured Risk Accruals

Basic is self-insured up to retention limits as it relates to workers’ compensation, general liability claims, 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, general liability claims, and medical and dental coverage of $500,000, $500,000, and $250,000, respectively. Basic has lower deductibles per occurrence for automobile 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, 2011 and December 31, 2010, self-insured risk accruals totaled approximately $16.8 million net of a $8,000 receivable for medical and dental coverage and $16.6 million net of a $164,000 receivable for medical and dental coverage, respectively.

7. Stockholders’ Equity

Common Stock

At June 30, 2011 and December 31, 2010, Basic had 80,000,000 shares of common stock, par value $.01 per share, authorized.

During the year ended 2010, Basic issued 53,975 shares of common stock from treasury stock upon the exercise of stock options.

In March 2010, Basic granted various employees 588,600 restricted shares of common stock which vest over a five-year period.

In March 2010, the Compensation Committee of Basic’s Board of Directors approved grants of performance-based stock awards to certain members of management. In February 2011, it was determined that 285,281 shares, or 150% of the target number of shares, were earned based on Basic’s achievement of total stockholder return over the performance period from January 1, 2010 through December 31, 2010, as compared to other members of a defined peer group. These restricted shares remain subject to vesting over a three-year period, with the first shares vesting on March 15, 2012.

In March 2011, Basic granted various employees 510,399 restricted shares of common stock that vest over a three-year period.

During the six months ended June 30, 2011, Basic issued 390,750 shares of common stock from treasury stock for the exercise of stock options and 37,500 shares of newly-issued common stock for the exercise of stock options.

Treasury Stock

Basic has acquired treasury shares through net share settlements for payment of payroll taxes upon the vesting of restricted stock. Basic acquired a total of 40,381 shares through net share settlements during 2010 and 76,077 shares through net share settlements during the first six months of 2011.

Preferred Stock

At June 30, 2011 and December 31, 2010, 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 Energy Services, Inc. 2003 Incentive Plan (as amended effective May 24, 2011) (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 predecessors that were awarded and remained outstanding prior to adoption of the Plan. The Plan provides for the issuance of 8,350,000 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.

During the three months ended June 30, 2011 and 2010, compensation expense related to share-based arrangements was approximately $2.1 million and $1.4 million, respectively. For compensation expense recognized during the three months ended June 30, 2011 and 2010, Basic recognized a tax benefit of approximately $930,000 and $577,000, respectively. During the six months ended June 30, 2011 and 2010, compensation expense related to share-based arrangements was approximately $3.8 million and $2.6 million, respectively. For compensation expense recognized during the six months ended June 30, 2011 and 2010, Basic recognized a tax benefit of approximately $1.5 million and $962,000, respectively.

As of June 30, 2011, there was approximately $20.0 million of total unrecognized compensation related to non-vested share-based compensation arrangements granted under the Plan. That cost is expected to be recognized over a weighted-average period of 2.86 years. The total fair value of share-based awards vested during the six months ended June 30, 2011 and 2010 was approximately $8.6 million and $3.8 million, respectively. The actual tax benefit realized for the tax deduction from vested share-based awards was $2.8 million and $578,000 for the six months ended June 30, 2011 and 2010, respectively.

Stock Option Awards

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. 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, 2011 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		1,414,450		$	11.44
Options granted		—
Options forfeited		(5,000	)	$	6.98
Options exercised		(428,250	)	$	6.71
Options expired		(3,000	)	$	26.84

Outstanding, end of period		978,200		$	13.49		3.67	$	17,592


Exercisable, end of period		955,200		$	13.27		3.62	$	17,389


Vested or expected to vest, end of period		973,600		$	13.44		3.66	$	17,551

The total intrinsic value of share options exercised during the six months ended June 30, 2011 and 2010 was approximately $8.3 million and $24,000, respectively.

Cash received from share option exercises under the Plan was approximately $2.9 million and $58,000 for the six months ended June 30, 2011 and 2010, respectively. The actual tax benefit realized for the tax deductions from options exercised was $3.0 million and $9,000 for the six months ended June 30, 2011 and 2010, respectively.

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

Restricted Stock Awards

On March 10, 2011, 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 Basic’s achievement of total stockholder return over the performance period from January 1, 2011 through December 31, 2011, 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 148,683 target number of shares 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, 2013. As of June 30, 2011, Basic estimated that 129.2% of the target number of performance-based awards will be earned.

A summary of the status of Basic’s non-vested share grants at June 30, 2011 and changes during the six months ended June 30, 2011 is presented in the following table:


				Weighted Average
	Number of			Grant Date Fair
Nonvested Shares	Shares			Value Per Share
Nonvested at beginning of period		1,802,573		$	11.06
Granted during period		702,931			19.49
Vested during period		(329,018	)		13.45
Forfeited during period		(74,023	)		12.65

Nonvested at end of period		2,102,463		$	13.44

9. Related Party Transactions

Basic had receivables from employees of approximately $44,000 and $42,000 as of June 30, 2011 and December 31, 2010, 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. In December 2010, Basic entered into a lease agreement with Darle Vuelta Cattle Co., LLC, for the right to operate a salt water disposal well, brine well and fresh water well. The term of the lease is two years and will continue until the salt water disposal well and brine well are plugged and no fresh water is being sold. The lease payments are the greater of the sum of $0.10 per barrel of disposed oil and gas waste and $0.05 per barrel of brine or fresh water sold, or $5,000 per month.

10. Earnings Per Share

Basic’s 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,
	2011		2010			2011			2010
	(Unaudited)					(Unaudited)
Numerator (both basic and diluted):
Net income (loss)	$	16,550	$	(10,672	)	$	(1,943	)	$	(32,263	)

Denominator:
Denominator for basic earnings (loss) per share		40,356,049		39,724,030			40,135,143			39,672,891

Stock options		422,110		—			—			—
Unvested restricted stock		557,505		—			—			—

Denominator for diluted earnings (loss) per share		41,335,664		39,724,030			40,135,143			39,672,891


Basic earnings (loss) per common share:	$	0.41	$	(0.27	)	$	(0.05	)	$	(0.81	)


Diluted earnings (loss) per common share:	$	0.40	$	(0.27	)	$	(0.05	)	$	(0.81	)

Stock options and unvested shares of restricted stock of approximately 524,000 were excluded in the computation of diluted earnings per share for the three months ended June 30, 2010, as the effect would have been anti-dilutive due to the net loss in the period. Stock options and unvested shares of restricted stock of approximately 1,222,000 and 859,000, respectively, were excluded in the computation of diluted earnings per share for the six months ended June 30, 2011 and 2010, 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 Completion and Remedial Services, Fluid Services, Well Servicing, and Contract Drilling. The following is a description of the segments:

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

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.

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 natural gas. These services are performed to establish, maintain and improve production throughout the productive life of an oil and natural 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. This segment also includes the manufacturing, refurbishment and servicing of mobile well servicing rigs and associated equipment.

Contract Drilling:This segment utilizes drilling 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
	and Remedial			Fluid			Well			Contract			Corporate
	Services			Services			Servicing			Drilling			and Other		Total
*Three Months Ended June 30, 2011 (Unaudited)*
Operating revenues	$	121,807		$	81,415		$	83,881		$	9,752		$	—	$	296,855
Direct operating costs		(68,827	)		(51,688	)		(57,409	)		(7,393	)		—	$	(185,317	)

Segment profits	$	52,980		$	29,727		$	26,472		$	2,359		$	—	$	111,538


Depreciation and amortization	$	9,841		$	10,359		$	10,398		$	2,326		$	1,860	$	34,784

Capital expenditures, (excluding acquisitions)	$	12,638		$	12,847		$	11,633		$	2,986		$	2,327	$	42,431

*Three Months Ended June 30, 2010 (Unaudited)*
Operating revenues	$	61,533		$	58,801		$	49,529		$	5,269		$	—	$	175,132
Direct operating costs		(37,660	)		(43,425	)		(36,734	)		(3,725	)		—		(121,544	)

Segment profits	$	23,873		$	15,376		$	12,795		$	1,544		$	—	$	53,588


Depreciation and amortization	$	8,121		$	9,478		$	12,562		$	1,882		$	2,207	$	34,250

Capital expenditures, (excluding acquisitions)	$	3,429		$	4,013		$	5,305		$	795		$	921	$	14,463

*Six Months Ended June 30, 2011 (Unaudited)*
Operating revenues	$	219,314		$	153,760		$	153,028		$	16,807		$	—	$	542,909
Direct operating costs		(123,760	)		(99,916	)		(105,849	)		(11,878	)		—	$	(341,403	)

Segment profits	$	95,554		$	53,844		$	47,179		$	4,929		$	—	$	201,506


Depreciation and amortization	$	17,909		$	19,764		$	22,351		$	4,233		$	3,507	$	67,764

Capital expenditures, (excluding acquisitions)	$	30,359		$	33,503		$	37,889		$	7,176		$	5,946	$	114,873
Identifiable assets	$	231,977		$	195,403		$	247,077		$	70,245		$	584,405	$	1,329,107

*Six Months Ended June 30, 2010 (Unaudited)*
Operating revenues	$	106,767		$	110,948		$	91,325		$	9,058		$	—	$	318,098
Direct operating costs		(67,383	)		(84,365	)		(68,834	)		(6,995	)		—	$	(227,577	)

Segment profits	$	39,384		$	26,583		$	22,491		$	2,063		$	—	$	90,521


Depreciation and amortization	$	15,952		$	18,895		$	24,703		$	3,716		$	4,082	$	67,348

Capital expenditures, (excluding acquisitions)	$	6,053		$	7,170		$	9,373		$	1,410		$	1,549	$	25,555
Identifiable assets	$	185,854		$	183,971		$	245,041		$	39,624		$	357,235	$	1,011,725

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,
	2011			2010			2011			2010
Segment profits	$	111,538		$	53,588		$	201,506		$	90,521

General and administrative expenses		(34,138	)		(26,820	)		(65,479	)		(51,897	)
Depreciation and amortization		(34,784	)		(34,250	)		(67,764	)		(67,348	)
Gain (loss) on disposal of assets		(942	)		(463	)		763			(1,174	)

Operating income (loss)	$	41,674		$	(7,945	)	$	69,026		$	(29,898	)

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,
	2011		2010
	(In thousands)
Capital leases issued for equipment	$	24,104	$	6,691
Asset retirement obligation additions	$	11	$	12

Basic paid no income taxes during the six months ended June 30, 2011 or for the same period in 2010. Basic paid interest of approximately $18.6 million and $21.8 million during the six months ended June 30, 2011 and 2010, respectively.

13. 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. Basic 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. Basic 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.

There is 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). Basic 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 Basic 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. Basic’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.

Basic’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, 2011 (in thousands):


	Asset
	Retirement
	Obligation
Balance, December 31, 2010	$	1,983

Additional asset retirement obligation		11
Accretion expense		65
Settlements		(57	)

Balance, June 30, 2011	$	2,002

14. Subsequent Events

On July 7, 2011, Basic completed the acquisition of substantially all of the operating assets of Lone Star Anchor Trucking, Inc. for total cash consideration of $10.1 million. This acquisition will operate in Basic’s fluid services segment.

On July 8, 2011, Basic completed the acquisition of the outstanding equity interests of the Maverick companies (“Maverick”) for total cash consideration of $180.0 million, net of working capital acquired. Maverick provides stimulation, coil tubing and thru-tubing services and will operate in Basic’s completion and remedial services segment.

On July 15, 2011, Basic amended its existing revolving credit facility, increasing the available credit from $165.0 million to $225.0 million. No changes were made to the collateral, interest rates, or guarantors as part of this amendment.

During July 2011, Basic received aggregate federal income tax refunds of approximately $80.1 million relating to Basic’s 2009 and 2010 tax returns.

ITEM 2.MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Management’s Overview

We provide a wide range of well site services to oil and natural gas drilling and producing companies, including completion and remedial services, fluid services and well site construction services, well servicing 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 our acquisition strategy, we purchased businesses and assets in four separate acquisitions from January 1, 2010 to June 30, 2011. Our weighted average number of fluid service trucks increased from 791 in the first quarter of 2010 to 837 in the second quarter of 2011. Our weighted average number of well servicing rigs increased from 405 in the first quarter of 2010 to 412 in the second quarter of 2011. 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):

Revenues:


	Six Months Ended June 30,
	2011				2010
Revenues:
Completion and remedial services	$	219.3	41	%	$	106.8	33	%
Fluid services		153.8	28	%		110.9	35	%
Well servicing		153.0	28	%		91.3	29	%
Contract drilling		16.8	3	%		9.1	3	%

Total revenues	$	542.9	100	%	$	318.1	100	%

Our core businesses depend on our customers’ willingness to make expenditures to produce, develop and explore for oil and natural gas in the United States. Industry conditions are influenced by numerous factors, such as the supply of and demand for oil and natural gas, domestic and worldwide economic conditions, political instability in oil producing countries and merger and divestiture activity among oil and natural gas producers. The volatility of the oil and natural gas industry, and the consequent impact on exploration and production activity, has adversely impacted, and could continue to 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 the first half of 2009, utilization and pricing for our services declined due to low oil and natural gas prices. In the third quarter of 2009, oil prices began to increase and remained relatively stable through 2010. In the first half of 2011, oil prices have increased, primarily due to political instability in several oil producing countries. This trend in oil prices has caused utilization and pricing for our services to increase in our oil-based operating areas. Utilization and pricing for our services in our natural gas-based operating areas throughout 2010 and in the first half of 2011 have remained depressed due to low natural gas prices.

We expect that our utilization levels across all of our business segments should show further improvements through the remainder of 2011 as demand continues to rise based on strong pricing, particularly in our established oil-oriented market areas. Despite current lower natural gas prices, discussions with customers indicate that demand in our natural gas-oriented market areas should remain flat with current levels.

We derive a significant portion of our revenues from services supporting production from existing oil and natural gas operations. Demand for these production-related services, including well servicing and fluid services, tends to remain relatively stable, even in moderate oil and natural gas price environments, as ongoing maintenance spending is required to sustain production. As oil and natural 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 natural gas prices increase or decrease.

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

•

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

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

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

	•		Contract Drilling — rig operating days, revenue per drilling day, profits 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 expand our business through selective acquisitions and internal growth initiatives. In July of 2011 we acquired substantially all of the operating assets of Lone Star Anchor Trucking, Inc. and all of the outstanding equity interests of the Maverick companies. 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 natural 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.

Selected Acquisitions

During 2010, we made four acquisitions that complemented our existing business segments. These included, among others:

Taylor Rig, LLC

On May 3, 2010, we acquired all the assets of Taylor Rig, LLC for total consideration of $8.7 million in cash. This acquisition has been included in our well servicing segment.

Platinum Pressure Services, Inc. and Admiral Well Service, Inc.

On December 16, 2010, we acquired all of the outstanding stock of Platinum Pressure Services, Inc. (“Platinum”) and Admiral Well Service, Inc., a wholly owned subsidiary of Platinum, for total cash consideration of $39.9 million including working capital. This acquisition operates in our completion and remedial services and well servicing segments.

During the first six months of 2011, we did not complete any material acquisitions.

Segment Overview

Completion and Remedial Services

During the first six months of 2011, our completion and remedial services segment represented 41% of our revenues. Revenues from our completion and remedial services segment are generally derived from a variety of services designed to complete and stimulate new oil and natural gas production or place cement slurry within the wellbores. Our completion and remedial services segment includes pumping services, rental and fishing tool operations, cased-hole wireline services, snubbing and underbalanced drilling.

Our pumping services concentrate on providing single truck, lower-horsepower cementing, acidizing and fracturing services in selected markets. Our total hydraulic horsepower capacity for our pressure pumping operations was 176,000 and 142,000 at June 30, 2011 and June 30, 2010, 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 2010, the full year ended December 31, 2010 and the quarters ended March 31, 2011 and June 30, 2011 (dollars in thousands):


			Segment
	Revenues		Profits%
2010:
First Quarter	$	45,234		34	%
Second Quarter	$	61,533		39	%
Third Quarter	$	73,725		41	%
Fourth Quarter	$	80,944		43	%
Full Year	$	261,436		40	%
2011:
First Quarter	$	97,507		44	%
Second Quarter	$	121,807		44	%

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

The increase in completion and remedial services revenue to $121.8 million in the second quarter of 2011 from $97.5 million in the first quarter of 2011 as a result of improved pricing and expansion of our fleets. Segment profit percentage remained flat at 44% for both the second quarter of 2011 and the first quarter of 2011.

Fluid Services

During the first six months of 2011, our fluid services segment represented 28% of our revenues. Revenues in our fluid services segment are earned from the sale, transportation, storage and disposal of fluids used in the drilling, production and maintenance of oil and natural gas wells. Revenues also include well site construction and maintenance services. The fluid services segment has a base level of business consisting of transporting and disposing of salt water produced as a by-product of the production of oil and natural 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. 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. 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 natural gas facilities. 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 2010, the full year ended December 31, 2010 and the quarters ended March 31, 2011 and June 30, 2011 (dollars in thousands):


	Weighted						Segment Profits
	Average Number of				Revenue Per		Per Fluid
	Fluid Service		Trucking		Fluid Service		Service		Segment
	Trucks		Hours		Truck		Truck		Profits%
2010:
First Quarter		791		431,700	$	66	$	14		22	%
Second Quarter		797		468,600	$	74	$	19		26	%
Third Quarter		789		475,200	$	80	$	20		25	%
Fourth Quarter		782		476,100	$	85	$	27		31	%
Full Year		790		1,851,600	$	305	$	80		26	%
2011:
First Quarter		820		494,700	$	88	$	29		33	%
Second Quarter		837		525,700	$	97	$	36		37	%

We gauge activity levels in our fluid services segment based on trucking hours, revenue and segment profits per fluid service truck, and segment profits as a percent of revenues.

Revenue per fluid service truck increased by 10% to $97,000 in the second quarter of 2011 compared to $88,000 in the first quarter of 2011, primarily due to the increasing rates being charged to customers and higher utilization for trucking and frac tank rentals. Segment profit percentage increased to 37% in the second quarter of 2011 from 33% in the first quarter of 2011.

Well Servicing

During the first six months of 2011, our well servicing segment represented 28% of our revenues. Revenue in our well servicing segment is derived from maintenance, workover, completion, manufacturing and plugging and abandonment services. We provide maintenance-related services as part of the normal, periodic upkeep of producing oil and natural 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 also have a rig manufacturing and servicing facility that builds new workover rigs, performs large-scale refurbishments of used workover rigs and provides maintenance services on previously manufactured rigs.

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 405 rigs in the first quarter of 2010 to 412 in the second quarter of 2011.

The following is an analysis of our well servicing operations for each of the quarters in 2010, the full year ended December 31, 2010 and the quarters ended March 31, 2011 and June 30, 2011:


	Weighted
	Average				Rig					Profits
	Number of		Rig		Utilization			Revenue Per		Per Rig		Segment
	Rigs		Hours		Rate			Rig Hour		Hour		Profits%
2010:
First Quarter		405		135,700		46.9	%	$	308	$	71		23	%
Second Quarter		404		153,900		53.3	%	$	316	$	83		26	%
Third Quarter		404		159,400		55.2	%	$	319	$	74		21	%
Fourth Quarter		407		164,400		56.5	%	$	331	$	90		24	%
Full Year		405		613,400		53.0	%	$	319	$	81		23	%
2011:
First Quarter		412		184,700		62.7	%	$	356	$	105		30	%
Second Quarter		412		205,700		69.8	%	$	376	$	122		32	%

We gauge activity levels in our well servicing segment based on rig hours, rig utilization rate, revenue per rig hour, segment profits per rig hour and segment profits as a percent of revenues. Revenue per rig hour and profits per rig hour in the table above do not include revenues and profits from the rig manufacturing and maintenance division of this business segment.

Rig utilization increased to 69.8% in the second quarter of 2011, compared to 62.7% in the first quarter of 2011. The increase was caused by improving economic conditions and increased oil prices that allowed our customers to increase spending. Our segment profit percentage increased slightly to 32% during the second quarter of 2011 from 30% during the first quarter of 2011.

Contract Drilling

During the first six months of 2011, 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 based on a seven-day work week per rig. Our contract drilling rig fleet had a weighted average of ten rigs during the second quarter of 2011 compared to a weighted average of six rigs in the first quarter of 2011, due to the purchase of four drilling rigs.

The following is an analysis of our contract drilling segment for each of the quarters in 2010, the full year ended December 31, 2010 and the quarters ended March 31, 2011 and June 30, 2011:


	Weighted
	Average		Rig
	Number of		Operating		Revenue		Profits		Segment
	Rigs		Days		Per Day		Per Day		Profits%
2010:
First Quarter		9		420	$	9,000	$	1,200		14	%
Second Quarter		9		527	$	10,000	$	2,900		29	%
Third Quarter		9		523	$	10,600	$	2,700		26	%
Fourth Quarter		6		536	$	11,500	$	3,800		33	%
Full Year		8		2,006	$	10,400	$	2,800		27	%
2011:
First Quarter		6		522	$	13,500	$	4,900		36	%
Second Quarter		10		714	$	13,700	$	3,300		24	%

We gauge activity levels in our drilling operations based on rig operating days, revenue per drilling day, profits per drilling day and segment profits as a percent of revenues.

The increase in revenue per day to $13,700 in the second quarter of 2011 from $13,500 in the first quarter of 2011 was due primarily to improved pricing for our services. The decrease in segment profit percentage to 24% in the second quarter of 2011 from 36% in the first quarter of 2011 was due to costs associated with the start-up of four drilling rigs purchased in 2011.

Operating Cost Overview

Our operating costs are comprised primarily of labor, including workers’ compensation and health insurance, repair and maintenance, fuel and insurance. The majority of our employees are paid on an hourly basis. We also incur costs to employ personnel to sell and supervise our services and perform maintenance on our fleet. These costs are not directly tied to our level of business activity. Compensation for our administrative personnel in local operating yards and in our corporate office is accounted for as general and administrative expenses. Repair and maintenance is performed by our crews, company maintenance personnel and outside service providers. Insurance is generally a fixed cost regardless of utilization and relates to the number of rigs, trucks and other equipment in our fleet, employee payroll and safety record.

Critical Accounting Policies and Estimates

Our unaudited consolidated financial statements are impacted by the accounting policies used and the estimates and assumptions made by management during their preparation. A complete summary of our critical accounting policies is included in note 2 of the notes to our historical audited consolidated financial statements in our most recent annual report on Form 10-K. The following is a discussion of our critical accounting policies and estimates.

Critical Accounting Policies

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

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

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

Self-Insured Risk Accruals.We are self-insured up to retention limits with regard to workers’ compensation, general liability claims, and medical and dental coverage of our employees. We generally maintain no physical property damage coverage on our workover rig fleet, with the exception of certain of our 24-hour workover rigs and newly manufactured rigs. We have deductibles per occurrence for workers’ compensation, general liability claims, and medical and dental coverage of $500,000, $500,000 and $250,000 respectively. We have lower deductibles per occurrence for automobile liability. We maintain accruals in our consolidated balance sheets related to self-insurance retentions by using third-party actuarial data and claims history.

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

Income Taxes.We recognize deferred tax assets and liabilities for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using statutory tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rate is recognized in the period that includes the statutory enactment date. A valuation allowance for deferred tax assets is recognized when it is more likely than not that the benefit of deferred tax assets will not be realized.

Critical Accounting Estimates

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

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

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

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

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

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

Fair Value of Assets Acquired and Liabilities Assumed.We estimate the fair value of assets acquired and liabilities assumed in business combinations, which involves the use of various assumptions. These estimates may be affected by such factors as changing

market conditions, technological advances in the industry or changes in regulations governing the industry. The most significant assumptions, and the ones requiring the most judgment, involve the estimated fair value of property and equipment, intangible assets and the resulting amount of goodwill, if any. We test annually for impairment the goodwill and intangible assets with indefinite useful lives recorded in business combinations. This requires us to estimate the fair values of our own assets and liabilities at the reporting unit level. Therefore, considerable judgment, similar to that described above in connection with our estimation of the fair value of an acquired company, is required to assess goodwill and certain intangible assets for impairment.

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

Stock-Based Compensation.Our stock-based awards consist of stock options and restricted stock. Stock options issued are valued on the grant date using the Black-Scholes-Merton option-pricing model and restricted stock issued is valued based on the fair value of our common stock at the grant date. All stock-based awards are adjusted for an expected forfeiture rate and amortized over the vesting period.

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

Asset Retirement Obligations.We record the fair value of an asset retirement obligation as a liability in the period in which we incur 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 settlement of obligations.

Results of Operations

The following is a comparison of our results of operations for the three months and six months ended June 30, 2011 compared to the three months and six months ended June 30, 2010, respectively. For additional segment-related information and trends, please read “— Segment Overview” above.

Three Months Ended June 30, 2011 Compared to Three Months Ended June 30, 2010

Revenues.Revenues increased by 70% to $296.9 million during the second quarter of 2011 from $175.1 million during the same period in 2010. This increase was primarily due to increased demand by our customers for our services, which resulted from higher commodity prices and drilling and well maintenance activity among our customers.

Completion and remedial services revenues increased by 98% to $121.8 million during the second quarter of 2011 compared to $61.5 million in the same period in 2010. The increase in revenue between these periods was due to improved utilization of equipment, resulting from higher drilling and completion activity, as well as improved pricing for our services. Total hydraulic horsepower increased to 176,000 at June 30, 2011 from 142,000 at June 30, 2010.

Fluid services revenues increased by 38% to $81.4 million during the second quarter of 2011 compared to $58.8 million in the same period in 2010. Our revenue per fluid service truck increased 31% to $97,000 in the second quarter of 2011 compared to $74,000 in the same period in 2010, which reflects increases in both utilization and pricing for our services. Our weighted average number of fluid service trucks increased 5% to 837 during the second quarter of 2011 from 797 in the same period in 2010.

Well servicing revenues increased by 69% to $83.9 million during the second quarter of 2011 compared to $49.5 million during the same period in 2010. The higher revenues were due to the 34% increase in rig hours to 205,700 during the second quarter of 2011 from 153,900 during the second quarter of 2010. There was also an increase in revenue per rig hour to $376 during the second quarter of 2011 from $316 during the second quarter of 2010. Our average number of well servicing rigs increased to 412 during the second quarter of 2011 compared to 404 in the same period in 2010, primarily due to the acquisition of Platinum Pressure Services, Inc. (“Platinum”) in the fourth quarter of 2010.

Contract drilling revenues increased by 85% to $9.8 million during the second quarter of 2011 compared to $5.3 million in the same period in 2010. The number of rig operating days increased 35% to 714 in the second quarter of 2011 compared to 527 in the second quarter of 2010. This increase was due to the addition of four drilling rigs in the first six months of 2011 and an increase in new well starts in the Permian Basin, a region in which all of our drilling rigs operate, along with higher dayrates.

Direct Operating Expenses.Direct operating expenses, which primarily consist of labor , including workers’ compensation and health insurance, repair and maintenance, fuel and insurance, increased by 53% to $185.3 million during the second quarter of 2011 from $121.5 million in the same period in 2010. This increase was primarily due to increased activity in each of our four business segments.

Direct operating expenses for the completion and remedial services segment increased by 83% to $68.8 million during the second quarter of 2011 as compared to $37.7 million for the same period in 2010 due primarily to personnel and other costs associated with increased activity levels overall and in our pumping services line. Segment profits increased to 44% of revenues during the second quarter of 2011 compared to 39% for the same period in 2010, due to higher utilization and improved pricing for our services.

Direct operating expenses for the fluid services segment increased by 19% to $51.7 million during the second quarter of 2011 as compared to $43.4 million for the same period in 2010, mainly due to personnel and other costs associated with increased activity levels. Segment profits were 37% of revenues during the second quarter of 2011 compared to 26% for the same period in 2010 due to improved pricing for our services.

Direct operating expenses for the well servicing segment increased by 56% to $57.4 million during the second quarter of 2011 as compared to $36.7 million for the same period in 2010. The increase in direct operating expenses was due to increased activity along with increased payroll, insurance and incentive compensation costs. Segment profits were 32% of revenues during the second quarter of 2011 compared to 26% for the same period in 2010 due to improved pricing and higher utilization for our services.

Direct operating expenses for the contract drilling segment increased to $7.4 million during the second quarter of 2011 from $3.7 million for the same period in 2010. Segment profits for this segment decreased to 24% of revenues during the second quarter of 2011 compared to 29% for the same period in 2010, primarily due to costs associated with the start-up of four drilling rigs purchased in 2011.

General and Administrative Expenses.General and administrative expenses increased by 27% to $34.1 million during the second quarter of 2011 from $26.8 million for the same period in 2010, due mainly to increased personnel costs, including payroll taxes and incentive compensation, and the full quarter effect of the general and administrative expense from the Platinum acquisition that was completed on December 16, 2010. General and administrative expenses included $2.1 million and $1.4 million of stock-based compensation expense during the second quarter of 2011 and 2010, respectively.

Depreciation and Amortization Expenses.Depreciation and amortization expenses were $34.8 million during the second quarter of 2011 as compared to $34.3 million for the same period in 2010.

Interest Expense.Interest expense remained flat at $11.8 million for both the second quarter of 2011 and the same period in 2010.

Income Tax Expense.There was income tax expense of $13.4 million during the second quarter of 2011 as compared to an income tax benefit of $7.1 million for the same period in 2010. Our effective tax rate during the second quarter of 2011 and 2010 was approximately 45% and 40%, respectively.

Six Months Ended June 30, 2011 Compared to Six Months Ended June 30, 2010

Revenues.Revenues increased by 71% to $542.9 million during the first six months of 2011 from $318.1 million during the same period in 2010. This increase was primarily due to increased expenditures by our customers for our services.

Completion and remedial services revenues increased by 105% to $219.3 million during the first six months of 2011 compared to $106.8 million in the same period in 2010. The increase in revenue between these periods was due primarily to improved utilization of equipment, resulting from higher drilling and completion activity, as well as improved pricing for our services. The increased revenues also reflect the impact of our Platinum business acquired in December 2010. Total hydraulic horsepower increased to 176,000 at June 30, 2011 from 142,000 at June 30, 2010.

Fluid services revenues increased by 39% to $153.7 million during the first six months of 2011 compared to $110.9 million in the same period in 2010. Our weighted average number of fluid service trucks increased by 4% to 828 during the first six months of 2011 from 794 in the same period in 2010, and our revenue per fluid service truck increased to $186,000 in the first six months of 2010 compared to $140,000 in the same period in 2010, which reflects the increase in utilization and pricing for these services.

Well servicing revenues increased by 68% to $153.0 million during the first six months of 2011 compared to $91.3 million during the same period in 2010. This increase was due to the 35% increase in rig hours to 390,400 during the first six months of 2011 from 289,600 during the same period in 2010. Revenue per rig hour increased 17% to $366 during the first six months of 2011 from $312 during the first six months of 2010, due to increased pricing and activity for our services. Our average number of well servicing rigs increased to 412 during the first six months of 2011 compared to 405 in the same period in 2010.

Contract drilling revenues increased by 86% to $16.8 million during the first six months of 2011 compared to $9.1 million in the same period in 2010. The number of rig operating days increased to 1,236 in the first six months of 2011 compared to 947 in the first six months of 2010. This increase was due to the addition of four drilling rigs in the first six months of 2011 and increases in new well starts in the Permian Basin, a region in which all of our drilling rigs operate, along with higher day rates.

Direct Operating Expenses.Direct operating expenses, which primarily consist of labor, including workers’ compensation and health insurance, fuel and maintenance and repair costs, increased by 50% to $341.4 million during the first six months of 2011 from $227.6 million in the same period in 2010. This increase was primarily due to the increased activity in each of our four business segments.

Direct operating expenses for the completion and remedial services segment increased by 84% to $123.8 million during the first six months of 2011 as compared to $67.4 million for the same period in 2010, due primarily to increased activity levels. Segment profits increased to 44% of revenues during the first six months of 2011 compared to 37% for the same period in 2010, due to higher utilization of our services and improved pricing for our services.

Direct operating expenses for the fluid services segment increased by 18% to $99.9 million during the first six months of 2011 as compared to $84.4 million for the same period in 2010. Segment profits were 35% of revenues during the first six months of 2011 compared to 24% for the same period in 2010, primarily due to increases in pricing along with increased activity levels.

Direct operating expenses for the well servicing segment increased by 54% to $105.8 million during the first six months of 2011 as compared to $68.8 million for the same period in 2010, while rig hours increased 35% to 390,400 in the first six months of 2011 from 289,600 for the same period in 2010. The increase in direct operating expenses is primarily due to the increase in rig hours. Segment profits were higher at 31% of revenues during the first six months of 2011 compared to 25% for the same period in 2010.

Direct operating expenses for the contract drilling segment increased by 70% to $11.9 million during the first six months of 2011 as compared to $7.0 million for the same period in 2010. Segment profits for this segment were 29% of revenues during the first six months of 2011 compared to 23% for the same period in 2010, mainly due to increases in pricing for our services.

General and Administrative Expenses.General and administrative expenses increased by 26% to $65.5 million during the first six months of 2011 from $51.9 million for the same period in 2010, which included $3.8 million and $2.6 million in stock-based compensation expense during the first six months of 2011 and 2010, respectively. The increase was primarily due to increased personnel costs, including payroll taxes, and the full six-month effect of the general and administrative expense from the Platinum acquisition that was completed on December 16, 2010.

Depreciation and Amortization Expenses.Depreciation and amortization expenses were $67.8 million during the first six months of 2011 as compared to $67.3 million for the same period in 2010, reflecting the increase in the size of and investment in our asset base.

Interest Expense.Interest expense remained flat at $23.2 million during the first six months of 2011 compared to $23.4 million for the same period in 2010.

Income Tax Expense.There was an income tax benefit of $1.3 million during the first six months of 2011 as compared to an income tax benefit of $19.1 million for the same period in 2010. Our effective tax rate during the first six months of 2011 and 2010 was approximately 40% and 37%, respectively.

Liquidity and Capital Resources

As of June 30, 2011, our primary capital resources were net proceeds from our 7.75% Senior Notes offerings, net cash flows from our operations, utilization of capital leases and our $165.0 million revolving credit facility. As of June 30, 2011, we had unrestricted cash and cash equivalents of $220.9 million compared to $47.9 million as of December 31, 2010. This increase was due in part to the issuance of $200.0 million of 7.75% notes in June 2011. We used $180.0 million of these proceeds to acquire the Maverick group of

companies on July 8, 2011. When appropriate, we will consider public or private debt and equity offerings and non-recourse transactions to meet our liquidity needs.

Net Cash Provided by Operating Activities

Cash provided by operating activities was $55.6 million for the six months ended June 30, 2011 as compared to cash used in operating activities of $1.6 million during the same period in 2010. Operating cash flow in the first six months of 2011 was higher mainly due to the increase in profitability due to higher revenues offset by the increase in accounts receivable.

Capital Expenditures

Capital expenditures are the main component of our investing activities. Cash capital expenditures (including acquisitions) during the first six months of 2011 were $114.9 million as compared to $35.9 million in the same period of 2010. We added $24.1 million of additional assets through our capital lease program during the first six months of 2011 compared to $6.7 million of additional assets in the same period in 2010.

For 2011, we now plan to spend at least $183 million for capital expenditures, including amounts spent to purchase four drilling rigs, of which $130 million will be paid for through operating cash flow and existing cash balances and the remainder through capital leases. Based on our view of short-term operating conditions, our capital expenditure program may be increased or decreased accordingly. The foregoing budget excludes acquisitions of other businesses. We do not budget acquisitions in the normal course of business, and we regularly engage in discussions related to potential acquisitions related to the well services industry.

Capital Resources and Financing

We currently believe that our operating cash flows, available funds from our revolving credit facility, and cash on hand will be sufficient to fund our near term liquidity requirements.

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

7.125% Senior Notes due 2016

In April 2006, we completed a private offering of $225.0 million aggregate principal amount of 7.125% Senior Notes due April 15, 2016 (the “7.125% Senior Notes”). The 7.125% Senior Notes were jointly and severally guaranteed by each of our restricted subsidiaries (currently all of our subsidiaries other than three immaterial subsidiaries). As of June 30, 2011, these three subsidiaries held no assets and performed no operations. The net proceeds from the offering were used to retire our outstanding Term B Loan balance and to pay down the outstanding balance under our previous credit facility. Remaining proceeds were used for general corporate purposes, including acquisitions.

We issued the 7.125% Senior Notes pursuant to an indenture, dated as of April 12, 2006, by and among us, the guarantor parties thereto and The Bank of New York Trust Company, N.A., as trustee (the “7.125% Senior Notes Indenture”).

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

The 7.125% Senior Notes Indenture contains covenants that limit our ability and the ability of certain of our subsidiaries to:

	•		incur additional indebtedness;

	•		pay dividends or repurchase or redeem capital stock;

	•		make certain investments;

	•		incur liens;

	•		enter into certain types of transactions with affiliates;

	•		limit dividends or other payments by restricted subsidiaries; and

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

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

Upon an Event of Default (as defined in the 7.125% Senior Notes Indenture), the trustee or the holders of at least 25% in aggregate principal amount of the 7.125% Senior Notes then outstanding may declare all of the amounts outstanding under the 7.125% Senior Notes to be due and payable immediately.

We may, at our option, redeem all or part of the 7.125% Senior Notes, at any time on or after April 15, 2011 at a redemption price equal to 100% of the principal amount thereof, plus a premium declining ratably to par and accrued and unpaid interest, if any, to the date of redemption.

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

11.625% Senior Secured Notes due 2014

On July 31, 2009, we issued $225.0 million aggregate principal amount of 11.625% Senior Secured Notes due 2014 (the “Senior Secured Notes”) in a private placement. The Senior Secured Notes were jointly and severally, and unconditionally, guaranteed on a senior secured basis initially by all of our current subsidiaries other than two immaterial subsidiaries.

The net proceeds from the issuance of the Senior Secured Notes were $207.7 million after discounts of $12.1 million and offering expenses of $5.2 million. We used the net proceeds from the offering, along with other funds, to repay all outstanding indebtedness under our $225.0 million revolving credit facility, which we terminated in connection with the offering.

The Senior Secured Notes and the related guarantees were issued pursuant to an indenture dated as of July 31, 2009 (the “Senior Secured Notes Indenture”), by and among us, the guarantors party thereto and The Bank of New York Mellon Trust Company, N.A., a national banking association, as trustee. The obligations under the Senior Secured Notes Indenture were secured as set forth in the Senior Secured Notes Indenture and in a Secured Notes Security Agreement, in favor of the trustee, by a first-priority lien (other than Permitted Collateral Liens, as defined in the Senior Secured Notes Indenture) in favor of the trustee, on the Collateral described in the Secured Notes Security Agreement.

Interest on the Senior Secured Notes accrued at a rate of 11.625% per year. Interest on the Senior Secured Notes was payable semi-annually in arrears on February 1 and August 1 of each year, commencing on February 1, 2010. The Senior Secured Notes provided for a maturity on August 1, 2014.

The Senior Secured Notes Indenture contained covenants that, among other things, limit our ability and the ability of certain of our subsidiaries to:

	•		incur additional indebtedness;

	•		pay dividends or repurchase or redeem capital stock;

	•		make certain investments;

	•		incur liens;

	•		enter into certain types of transactions with our affiliates;

	•		limit dividends or other payments by our restricted subsidiaries to us; and

	•		sell assets (including Collateral under the Secured Notes Security Agreement), or consolidate or merge with or into other companies.

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

On February 1, 2011, Basic announced a cash tender offer and consent solicitation with respect to any and all of the $225.0 million aggregate outstanding principal amount of the Senior Secured Notes. On February 15, 2011, Basic completed the closing for an early tender for approximately $224.7 million of the Senior Secured Notes and delivered to the trustee amounts required to satisfy and discharge remaining obligations for the outstanding notes. The tender offer expired on March 2, 2011, and as of June 30, 2011, all obligations of Basic under the Senior Secured Notes Indenture have been satisfied and no Senior Secured Notes remain outstanding.

7.75% Senior Notes due 2019

On February 15, 2011, we successfully completed the issuance and sale of $275.0 million and on June 13, 2011, we successfully completed the issuance and sale of an additional $200.0 million, for an aggregate principal amount of $475.0 million of 7.75% Senior Notes due 2019 (the “7.75% Senior Notes”). The 7.75% Senior Notes are jointly and severally, and unconditionally, guaranteed on a senior unsecured basis initially by all of our current subsidiaries other than three immaterial subsidiaries. The 7.75% Senior Notes and the guarantees rank (i) equally in right of payment with any of our and the subsidiary guarantors’ existing and future senior indebtedness, including our existing 7.125% Senior Notes and the related guarantees, and (ii) effectively junior to all existing or future liabilities of our subsidiaries that do not guarantee the 7.75% Senior Notes and to our and the subsidiary guarantors’ existing or future secured indebtedness to the extent of the value of the collateral therefor.

The 7.75% Senior Notes and the guarantees were offered and sold in private transactions in accordance with Rule 144A and Regulation S under the Securities Act of 1933, as amended. The purchase price for the $275.0 million of 7.75% Senior Notes issued on February 15, 2011 and guarantees was 100.000% of their principal amount and the purchase price for the $200.0 million of 7.75% Senior Notes issued on June 13, 2011 and guarantees was 101.000%, plus accrued interest from February 15, 2011. We received net proceeds from the issuance of the 7.75% Senior Notes of approximately $465.5 million after premiums and offering expenses. We used a portion of the net proceeds from the offering to fund our tender offer and consent solicitation for our Senior Secured Notes and to redeem the Senior Secured Notes not purchased in the tender offer. We also used a portion of the net proceeds from this offering to fund the $180.0 million purchase price for our Maverick companies acquisition completed in July 2011 and for general corporate purposes.

The 7.75% Senior Notes and the guarantees were issued pursuant to an indenture dated as of February 15, 2011 (the “7.75% Senior Notes Indenture”), by and among us, the guarantors party thereto and Wells Fargo Bank, N.A., as trustee. Interest on the 7.75% Senior Notes accrues from and including February 15, 2011 at a rate of 7.75% per year. Interest on the 7.75% Senior Notes is payable semi-annually in arrears on February 15 and August 15 of each year, commencing on August 15, 2011. The 7.75% Senior Notes mature on February 15, 2019.

The 7.75% Senior Notes Indenture contains covenants that, among other things, limit our ability and the ability of certain of our subsidiaries to:

	•		incur additional indebtedness;

	•		pay dividends or repurchase or redeem capital stock;

	•		make certain investments;

	•		incur liens;

	•		enter into certain types of transactions with affiliates;

	•		limit dividends or other payments by our restricted subsidiaries to us; and

•

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

These and other covenants that are contained in the 7.75% Senior Notes Indenture are subject to important exceptions and qualifications.

Additionally, during any period of time that the 7.75% Senior Notes have a Moody’s rating of Baa3 or higher or an Standard & Poor’s rating of BBB- or higher and no default has occurred and is then continuing, certain of the restrictive covenants contained in the 7.75% Senior Notes Indenture will cease to apply.

We may, at our option, redeem all or part of the 7.75% Senior Notes, at any time on or after February 15, 2015, at a redemption price equal to 100% of the principal amount thereof, plus a premium declining ratably to par and accrued and unpaid interest to the date of redemption.

At any time before February 15, 2014, we, at our option, may redeem up to 35% of the aggregate principal amount of the 7.75% Senior Notes issued under the 7.75% Senior Notes Indenture with the net cash proceeds of one or more qualified equity offerings at a redemption price of 107.750% of the principal amount of the 7.75% Senior Notes to be redeemed, plus accrued and unpaid interest to the date of redemption, as long as:

	•		at least 65% of the aggregate principal amount of the 7.75% Senior Notes issued under the 7.75% Senior Notes Indenture remains outstanding immediately after the occurrence of such redemption; and

	•		such redemption occurs within 90 days of the date of the closing of any such qualified equity offering.

In addition, at any time before February 15, 2015, we may redeem some or all of 7.75% Senior Notes at a redemption price equal to 100% of the principal amount of the 7.75% Senior Notes, plus an applicable premium and accrued and unpaid interest to the date of redemption.

Following a change of control, as defined in the 7.75% Senior Notes Indenture, Basic will be required to make an offer to repurchase all or a portion of the 7.75% Senior Notes at 101% of their principal amount, plus accrued and unpaid interest to the date of repurchase.

New Revolving Credit Facility

On February 15, 2011, in connection with the initial offering of 7.75% Senior Notes, we terminated our previous $30.0 million secured revolving credit facility with Capital One, National Association, and entered into a new $165.0 million revolving credit facility (the “Credit Agreement”) with Merrill Lynch, Pierce, Fenner & Smith Incorporated and Capital One, National Association, as joint lead arrangers and joint book managers, the lenders party thereto and Bank of America, N.A., as administrative agent. The Credit Agreement includes an accordion feature whereby the total credit available to Basic can be increased by up to $100.0 million under certain circumstances, subject to additional lender commitments. The obligations under the Credit Agreement are guaranteed on a joint and several basis by each of Basic’s current subsidiaries, other than three immaterial subsidiaries, and are secured by substantially all assets of Basic and the guarantors as collateral under a related Security Agreement (the “Security Agreement”). As of June 30, 2011, the non-guarantor subsidiaries held no assets and performed no operations. On July 15, 2011, we exercised the accordion feature and amended the Credit Agreement to increase our total credit available from $165.0 million to $225.0 million.

The Credit Agreement contains various covenants that, subject to agreed upon exceptions, limit Basic’s ability and the ability of certain of Basic’s subsidiaries to:

	•		incur indebtedness;

	•		grant liens;

	•		enter into sale and leaseback transactions;

	•		make loans, capital expenditures, acquisitions and investments;

	•		change the nature of business;

	•		acquire or sell assets or consolidate or merge with or into other companies;

	•		declare or pay dividends;

	•		enter into transactions with affiliates;

	•		enter into burdensome agreements;

	•		prepay, redeem or modify or terminate other indebtedness;

	•		change accounting policies and reporting practices; and

	•		amend organizational documents.

	•		a minimum consolidated interest coverage ratio of not less than 2.50:1.00;

	•		a maximum consolidated leverage ratio not to exceed:

	•		4.25:1.00 for the quarter ending March 31, 2011; and

	•		4.00:1.00 after March 31, 2011; and

•

a maximum consolidated senior secured leverage ratio of 2.00:1.00.

We had $21.9 million outstanding under the Credit Agreement as of June 30, 2011. At June 30, 2011, we were in compliance with our covenants under the Credit Agreement.

Other Debt

We have a variety of other capital leases and notes payable outstanding that is generally customary in our business. None of these debt instruments is material individually. Our leases with Banc of America Leasing & Capital, LLC require us to maintain a minimum debt service coverage ratio of 1.05 to 1.00. As of June 30, 2011, we had total capital leases of approximately $66.2 million.

Preferred Stock

At June 30, 2011 and December 31, 2010, we had 5,000,000 shares of $.01 par value preferred stock authorized, of which none was designated, issued or outstanding.

Other Matters

Off-Balance Sheet Arrangements

We have no off-balance sheet arrangements that have or are reasonably likely to have a current or future effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to investors.

Net Operating Losses

As of June 30, 2011, we had approximately $41.6 million of net operating loss carryforwards.

Recent Accounting Pronouncements

In December 2010, the FASB issued ASU No. 2010-09, “Business Combinations: Disclosure of Supplementary Pro Forma Information for Business Combinations”(“ASU 2010-29”). ASU 2010-29 addresses diversity in the interpretation of the pro forma revenue and earnings disclosure requirements for business combinations. If a public entity presents comparative financial statements, the entity should disclose revenue and earnings of the combined entity as though the business combination that occurred during the current year had occurred as of the beginning of the comparable prior annual reporting period only. Basic adopted ASU 2010-29 on January 1, 2011. This update had no impact on Basic’s financial position, results of operations or cash flows.

Impact of Inflation on Operations

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

ITEM 3.QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

As of June 30, 2011, we had no material changes to the disclosure on this matter made in our Annual Report on Form 10-K for the year ended December 31, 2010.

ITEM 4.CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

Based on their evaluation as of the end of the period covered by this report, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) are effective to ensure that information required to be disclosed in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and effective to ensure that information required to be disclosed in such reports is accumulated and communicated to our management, including our principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure.

Changes in Internal Control Over Financial Reporting

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

PART II — OTHER INFORMATION

ITEM 1.LEGAL PROCEEDINGS

From time to time, Basic is a party to litigation or other legal proceedings that Basic considers to be a part of the ordinary course of business. Basic is not currently involved in any legal proceedings that it considers probable or reasonably possible, individually or in the aggregate, to result in a material adverse effect on its financial condition, results of operations or liquidity. The information regarding litigation and environmental matters described in note 6 of the notes to our unaudited consolidated financial statements included in this Quarterly Report on Form 10-Q is incorporated herein by reference.

ITEM 1A.RISK FACTORS

For information regarding risks that may affect our business, see the risk factors included in our most recent annual report on Form 10-K under the heading “Risk Factors.”

In addition to the risk factors disclosed in our Form 10-K, the following are additional risk factors that should be considered in connection with our business:

Federal and state legislative and regulatory initiatives related to hydraulic fracturing could result in operating restrictions or delays in the completion of oil and natural gas wells that may reduce demand for our well servicing activities and could adversely affect our financial position, results of operations and cash flows.

We provide hydraulic fracturing services to our customers. Hydraulic fracturing is a commonly used process that involves injection of water, sand, and certain chemicals to fracture the hydrocarbon-bearing rock formation to allow flow of hydrocarbons into the wellbore. The federal Energy Policy Act of 2005 amended the Underground Injection Control (“UIC”) provisions of the federal Safe Drinking Water Act (“SDWA”) to exclude certain hydraulic fracturing practices from the definition of “underground injection”. The EPA has asserted regulatory authority over certain hydraulic fracturing activities involving diesel fuel and has begun the process of drafting guidance relating to such practices. In addition, repeal of the SDWA exclusion of hydraulic fracturing has been advocated by certain advocacy organizations and others in the public. In March 2011, companion bills entitled the Fracturing Responsibility and Awareness of Chemicals (FRAC) Act were reintroduced in the United States Senate and House of Representatives. These bills, which are currently under consideration by Congress, would repeal the exemption for hydraulic fracturing from the SDWA, which would have the effect of allowing the EPA to promulgate new regulations and permitting requirements for hydraulic fracturing, and would require the disclosure of the chemical constituents of hydraulic fracturing fluids to a regulatory agency, which would make the information public via the internet. Scrutiny of hydraulic fracturing activities continues in other ways, with the EPA having commenced a study of the potential environmental impacts of hydraulic fracturing, the initial results of which are expected to be available by late 2012 and the final results of which are expected in 2014. The U.S. Department of the Interior has also announced that it will consider regulations relating to the use of hydraulic fracturing techniques on public lands and disclosure of fracturing fluid constituents. In addition, some states and localities have adopted, and others are considering adopting, regulations or ordinances that could restrict hydraulic fracturing in certain circumstances, that would require, with some exceptions, disclosure of constituents of hydraulic fracturing fluids, or that would impose higher taxes, fees or royalties on natural gas production. Moreover, public debate over hydraulic fracturing and shale gas production has been increasing, and has resulted in delays of well permits in some areas.

In 2010, a committee of the U.S. House of Representatives undertook investigations into hydraulic fracturing practices involving the use of diesel fuel in hydraulic fracturing fluids, including requesting information from various field services companies including us. We responded to that request and have received no further communication from the committee with regard to that investigation. However, on January 31, 2011, Representative Henry Waxman and other members of Congress wrote to the EPA asserting that various companies, including us, had engaged in hydraulic fracturing operations requiring a permit without obtaining such a permit. We have no knowledge as to whether or how the EPA will respond to that letter.

Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition, including litigation, to oil and gas production activities using hydraulic fracturing techniques. Additional legislation or regulation could also lead to operational delays or increased operating costs in the production of oil and natural gas, including from the developing shale plays, incurred by our customers or could make it more difficult to perform hydraulic fracturing. The adoption of any federal, state or local laws or the implementation of regulations or ordinances restricting or increasing the costs of hydraulic fracturing could potentially increase our costs of operations and cause a decrease in the completion of new oil and natural gas wells and an associated decrease in demand for our well servicing activities, any or all of which could adversely affect our financial position, results of operations and cash flows.

Potential listing of species as “endangered” under the federal Endangered Species Act could result in increased costs and new operating restrictions or delays on our oil and natural gas exploration and production customers, which could adversely reduce the amount of contract drilling services that we provide to such customers.

The federal Endangered Species Act, referred to as the “ESA,” and analogous state laws regulate a variety of activities, including oil and gas development, which could have an adverse effect on species listed as threatened or endangered under the ESA or their habitats. The designation of previously unidentified endangered or threatened species could cause oil and natural gas exploration and production operators to incur additional costs or become subject to operating delays, restrictions or bans in affected areas, which impacts could adversely reduce the amount of drilling activities in affected areas, including support services that we provide to such operators under our contract drilling services segment. Numerous species have been listed or proposed for protected status in areas in which we provide or could in the future provide field services. For instance, the Sand Dune Lizard, referred to as “Lizard,” a small lizard found in southeastern New Mexico and west Texas, an area where we provide a significant level of contract drilling services to oil and natural gas exploration and production operators, was proposed for listing as an endangered species under the ESA in December 2010 by the U.S. Fish & Wildlife Service, also referred to as the “FWS”. The lesser prairie chicken, sage grouse and certain wildflower species, among others, are also species that have been or are being considered for protected status under the ESA and whose range can coincide with oil and natural gas production activities. The presence of protected species in areas where operators whom we provide contract drilling services conduct exploration and production operations could impair such operators’ ability to timely complete well drilling and development and, consequently, adversely affect the amount of contract drilling or other field services that we provided to such operators, which reduction of services could have a significant adverse effect on our results of operations and financial position.

We are subject to environmental, health and safety laws and regulations that may expose us to significant liabilities for penalties, damages or costs of remediation or compliance.

Our operations are subject to federal, regional, state and local laws and regulations relating to protection of natural resources and the environment, health and safety aspects of our operations and waste management, including the transportation and disposal of waste and other materials. These laws and regulations may impose numerous obligations on our operations, including the acquisition of permits to conduct regulated activities, the incurrence of capital expenditures to mitigate or prevent releases of materials from our facilities, the imposition of substantial liabilities for pollution resulting from our operations and the application of specific health and safety criteria addressing worker protection. Failure to comply with these laws and regulations could result in investigations such as the investigation described in note 6 of the notes to our unaudited consolidated financial statements included in this Quarterly Report on Form 10-Q, restrictions or orders suspending well operations, the assessment of administrative, civil and criminal penalties, the revocation of permits and the issuance of corrective action orders, any of which could have a material adverse effect on our business, results of operations and financial condition.

There is inherent risk of environmental costs and liabilities in our business as a result of our handling of petroleum hydrocarbons and oilfield and industrial wastes, air emissions and wastewater discharges related to our operations, and historical industry operations and waste disposal practices. Our fluid services segment includes disposal operations into injection wells that pose risks of environmental liability, including leakage from the wells to surface or subsurface soils, surface water or groundwater. Some environmental laws and regulations may impose strict liability, which means that in some situations, we could be exposed to liability as a result of our conduct that was without fault or lawful at the time it occurred or as a result of the conduct of, or conditions caused by, prior operators or other third parties. Clean-up costs and other damages arising as a result of environmental laws and costs associated with changes in environmental laws and regulations could be substantial and could have a material adverse effect on our financial condition and results of operations.

Laws protecting the environment generally have become more stringent over time and are expected to continue to do so, which could lead to material increases in costs for future environmental compliance and remediation. The modification or interpretation of existing laws or regulations, or the adoption of new laws or regulations, could curtail exploratory or developmental drilling for oil and natural gas and could limit well servicing opportunities. We may not be able to recover some or any of our costs of compliance with these laws and regulations from insurance.

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

Purchase of Equity Securities by the Issuer and Affiliated Purchasers

The following table summarizes stock repurchase activity for the three months ended June 30, 2011:


	Issuer Purchases of Equity Securities
					Total Number of		Approximate Dollar Value
					Shares Purchased as		of Shares that May Yet
	Total Number of		Average Price Paid		Part of Publicly		be Purchased Under
Period	Shares Purchased (1)		per Share		Announced Program		the Program
April 1 — April 30		590	$	24.76		—	$	—
May 1 — May 31		1,129	$	27.52		—	$	—
June 1 — June 30		—	$	—		—	$	—
Total		1,719	$	26.57		—	$	—


(1)		These shares were repurchased from various employees to provide such employees the cash amounts necessary to pay certain tax liabilities associated with the vesting of restricted shares owned by them. The shares were repurchased on various dates based on the closing price per share on the date of repurchase.

ITEM 6.EXHIBITS


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

3.2*		Amended and Restated Bylaws of the Company, effective as of March 9, 2010. (Incorporated by reference to Exhibit 3.1 of the Company’s Current Report on Form 8-K (SEC File No. 001-32693), filed on March 15, 2010)

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

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

4.3*		Form of 7.125% Senior Note due 2016. (Included in the Indenture filed as Exhibit 4.1 of the Company’s Current Report on Form 8-K (SEC File No. 001-32693), filed on April 13, 2006)

4.4*		First Supplemental Indenture dated as of July 14, 2006 to Indenture dated as of April 12, 2006 among the Company as Issuer, the Subsidiary Guarantors named therein and The Bank of New York Trust Company, N.A., as trustee. (Incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K (SEC File No. 001-32693), filed on July 20, 2006)

4.5*		Second Supplemental Indenture dated as of April 26, 2007 and effective as of March 7, 2007 to Indenture dated as of April 12, 2006 among the Company as Issuer, the Subsidiary Guarantors named therein and the Bank of New York Trust Company, N.A., as trustee. (Incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K (SEC File No 001-32693), filed on May 1, 2007)

4.6*		Third Supplemental Indenture dated as of April 26, 2007 to Indenture dated as of April 12, 2006 among the Company as Issuer, the Subsidiary Guarantors named therein and the Bank of New York Trust Company, N.A., as trustee. (Incorporated by reference to Exhibit 4.2 of the Company’s Current Report on Form 8-K (SEC File No 001-32693), filed on May 1, 2007)

4.7*		Fourth Supplemental Indenture dated as of February 9, 2009 to Indenture dated as of April 12, 2006 among the Company as Issuer, the Subsidiary Guarantors named therein and the Bank of New York Mellon Trust Company, N.A., as Trustee. (Incorporated by reference to Exhibit 4.7 of the Company’s Annual Report on Form 10-K (SEC File No. 001-32693), filed on March 9, 2009)

4.8*		Fifth Supplemental Indenture dated as of July 23, 2009 to Indenture dated as of April 12, 2006 among the Company as Issuer, the Subsidiary Guarantors named therein and the Bank of New York Mellon Trust Company, N.A., as Trustee. (Incorporated by reference to Exhibit 4.8 of the Company’s Annual Report on Form 10-K (SEC File No. 001-32693), filed on March 1, 2010)

4.9*		Sixth Supplemental Indenture dated as of December 22, 2010 to Indenture dated as of April 12, 2006, by and among Basic Energy Services, Inc. as Issuer, the Subsidiary Guarantors named therein and The Bank of New York Mellon Trust Company, N.A. as trustee. (Incorporated by reference to Exhibit 10.4 of the Company’s Current Report on Form 8-K (SEC File No. 001-32693), filed on December 22, 2010)

4.10*		Indenture dated as of February 15, 2011, among Basic Energy Services, Inc. as Issuer, the Guarantors named therein and Wells Fargo Bank, N.A., as trustee. (Incorporated by reference to Exhibit 4.2 of the Company’s Current Report on Form 8-K (SEC File No. 001-32693), filed on February 18, 2011)

4.11*		Form of 7.75% Senior Note due 2019. (Included as Exhibit A to Exhibit 4.2 of the Company’s Current Report on Form 8-K (SEC File No. 001-32693), filed on February 18, 2011)

4.12*		Registration Rights Agreement dated as of February 15, 2011, by and among Basic, the Guarantors named therein and the initial purchasers party thereto. (Incorporated by reference to Exhibit 4.4 of the Company’s Current Report on Form 8-K (SEC File No. 001-32693), filed on February 18, 2011)

4.13*		Registration Rights Agreement dated as of June 13, 2011, by and among Basic, the Guarantors named therein and the initial purchasers party thereto. (Incorporated by reference to Exhibit 4.3 of the Company’s Current Report on Form 8-K (SEC File No. 001-32693), filed on June 13, 2011)

10.1*		First Amendment to Fourth Amended and Restated Basic Energy Services, Inc. 2003 Incentive Plan. (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K/A (SEC File No. 001-32693), filed on June 1, 2011)

10.2*		Amendment No. 1 to Credit Agreement, dated as of June 7, 2011, by and among Basic as Borrower, the lenders party thereto and Bank of America, N.A., as administrative agent, a swing line lender and l/c issuer. (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K (SEC File No. 001-32693), filed on June 7, 2011)

10.3*		Amendment No. 2 to Credit Agreement, dated as of July 15, 2011, by and among Basic as Borrower, the lenders party thereto and Bank of America, N.A., as administrative agent, a swing line lender and l/c issuer. (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K (SEC File No. 001-32693), filed on July 21, 2011)

10.4*		Purchase and Sale Agreement dated as of July 6, 2011, by and among Maverick Stimulation Company, LLC, Maverick Coil Tubing Services, LLC, MCM Holdings, LLC, Maverick Thru-Tubing, LLC, The Maverick Companies, LLC, Maverick Solutions, LLC, MSM Leasing, LLC and the sellers listed therein and Basic Energy Services, L.P. (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K (SEC File No. 001-32693), filed on July 11, 2011)


Exhibit
No.		Description
31.1#		Certification by Chief Executive Officer required by Rule 13a-14(a) and 15d-14(a) under the Exchange Act

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

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

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

101.CAL#		XBRL Calculation Linkbase Document

101.DEF#		XBRL Definition Linkbase Document

101.INS#		XBRL Instance Document

101.LAB#		XBRL Labels Linkbase Document

101.PRE#		XBRL Presentation Linkbase Document

101.SCH#		XBRL Schema Document


*		Incorporated by reference

#		Filed with this report

SIGNATURES

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


	BASIC ENERGY SERVICES, INC.
By :	/s/ Kenneth V. Huseman
	Name:	Kenneth V. Huseman
	Title:	President, Chief Executive Officer and Director (Principal Executive Officer)



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

Date: July 25, 2011

Exhibit Index


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

3.2*		Amended and Restated Bylaws of the Company, effective as of March 9, 2010. (Incorporated by reference to Exhibit 3.1 of the Company’s Current Report on Form 8-K (SEC File No. 001-32693), filed on March 15, 2010)

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

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

4.3*		Form of 7.125% Senior Note due 2016. (Included in the Indenture filed as Exhibit 4.1 of the Company’s Current Report on Form 8-K (SEC File No. 001-32693), filed on April 13, 2006)

4.4*		First Supplemental Indenture dated as of July 14, 2006 to Indenture dated as of April 12, 2006 among the Company as Issuer, the Subsidiary Guarantors named therein and The Bank of New York Trust Company, N.A., as trustee. (Incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K (SEC File No. 001-32693), filed on July 20, 2006)

4.5*		Second Supplemental Indenture dated as of April 26, 2007 and effective as of March 7, 2007 to Indenture dated as of April 12, 2006 among the Company as Issuer, the Subsidiary Guarantors named therein and the Bank of New York Trust Company, N.A., as trustee. (Incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K (SEC File No 001-32693), filed on May 1, 2007)

4.6*		Third Supplemental Indenture dated as of April 26, 2007 to Indenture dated as of April 12, 2006 among the Company as Issuer, the Subsidiary Guarantors named therein and the Bank of New York Trust Company, N.A., as trustee. (Incorporated by reference to Exhibit 4.2 of the Company’s Current Report on Form 8-K (SEC File No 001-32693), filed on May 1, 2007)

4.7*		Fourth Supplemental Indenture dated as of February 9, 2009 to Indenture dated as of April 12, 2006 among the Company as Issuer, the Subsidiary Guarantors named therein and the Bank of New York Mellon Trust Company, N.A., as Trustee. (Incorporated by reference to Exhibit 4.7 of the Company’s Annual Report on Form 10-K (SEC File No. 001-32693), filed on March 9, 2009)

4.8*		Fifth Supplemental Indenture dated as of July 23, 2009 to Indenture dated as of April 12, 2006 among the Company as Issuer, the Subsidiary Guarantors named therein and the Bank of New York Mellon Trust Company, N.A., as Trustee. (Incorporated by reference to Exhibit 4.8 of the Company’s Annual Report on Form 10-K (SEC File No. 001-32693), filed on March 1, 2010)

4.9*		Sixth Supplemental Indenture dated as of December 22, 2010 to Indenture dated as of April 12, 2006, by and among Basic Energy Services, Inc. as Issuer, the Subsidiary Guarantors named therein and The Bank of New York Mellon Trust Company, N.A. as trustee. (Incorporated by reference to Exhibit 10.4 of the Company’s Current Report on Form 8-K (SEC File No. 001-32693), filed on December 22, 2010)

4.10*		Indenture dated as of February 15, 2011, among Basic Energy Services, Inc. as Issuer, the Guarantors named therein and Wells Fargo Bank, N.A., as trustee. (Incorporated by reference to Exhibit 4.2 of the Company’s Current Report on Form 8-K (SEC File No. 001-32693), filed on February 18, 2011)


Exhibit
No.		Description
4.11*		Form of 7.75% Senior Note due 2019. (Included as Exhibit A to Exhibit 4.2 of the Company’s Current Report on Form 8-K (SEC File No. 001-32693), filed on February 18, 2011)

4.12*		Registration Rights Agreement dated as of February 15, 2011, by and among Basic, the Guarantors named therein and the initial purchasers party thereto. (Incorporated by reference to Exhibit 4.4 of the Company’s Current Report on Form 8-K (SEC File No. 001-32693), filed on February 18, 2011)

4.13*		Registration Rights Agreement dated as of June 13, 2011, by and among Basic, the Guarantors named therein and the initial purchasers party thereto. (Incorporated by reference to Exhibit 4.3 of the Company’s Current Report on Form 8-K (SEC File No. 001-32693), filed on June 13, 2011)

10.1*		First Amendment to Fourth Amended and Restated Basic Energy Services, Inc. 2003 Incentive Plan (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K/A (SEC File No. 001-32693), filed on June 1, 2011)

10.2*		Amendment No. 1 to Credit Agreement, dated as of June 7, 2011, by and among Basic as Borrower, the lenders party thereto and Bank of America, N.A., as administrative agent, a swing line lender and l/c issuer. (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K (SEC File No. 001-32693), filed on June 7, 2011)

10.3*		Amendment No. 2 to Credit Agreement, dated as of July 15, 2011, by and among Basic as Borrower, the lenders party thereto and Bank of America, N.A., as administrative agent, a swing line lender and l/c issuer. (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K (SEC File No. 001-32693), filed on July 21, 2011)

10.4*		Purchase and Sale Agreement dated as of July 6, 2011, by and among Maverick Stimulation Company, LLC, Maverick Coil Tubing Services, LLC, MCM Holdings, LLC, Maverick Thru-Tubing, LLC, The Maverick Companies, LLC, Maverick Solutions, LLC, MSM Leasing, LLC and the sellers listed therein and Basic Energy Services, L.P. (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K (SEC File No. 001-32693), filed on July 11, 2011)

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

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

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

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

101.CAL#		XBRL Calculation Linkbase Document

101.DEF#		XBRL Definition Linkbase Document

101.INS#		XBRL Instance Document

101.LAB#		XBRL Labels Linkbase Document

101.PRE#		XBRL Presentation Linkbase Document

101.SCH#		XBRL Schema Document


*		Incorporated by reference

#		Filed with this report

Positive
Negative
Uncertain
Constraining
Legalese
Litigous
Readability	H.S. freshman Avg

Basic Energy Services (BASWQ) 10-Q2011 Q2 Quarterly report

Content analysis