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

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

Commission File Number: 001-35255

C&J Energy Services, Inc.

(Exact name of registrant as specified in its charter)

Delaware		20-5673219
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

10375 Richmond Avenue, Suite 2000 Houston, Texas		77042
(Address of principal executive offices)		(Zip Code)

Registrant’s telephone number, including area code: (713) 260-9900

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

Yes o       No þ

     Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

Yes þ       No o

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

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

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

Yes o       No þ

     The number of shares of the registrant’s common stock, par value $0.01 per share, outstanding at August 26, 2011, was 51,886,574.

 

 

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES
TABLE OF CONTENTS

		Page
PART I – FINANCIAL INFORMATION
Item 1. Financial Statements
Consolidated Balance Sheets at June 30, 2011 and December 31, 2010			1
Consolidated Statements of Operations for the three and six months ended June 30, 2011 and 2010			2
Consolidated Statements of Changes in Stockholders’ Equity			3
Consolidated Statements of Cash Flows for the six months ended June 30, 2011 and 2010			4
Notes to Consolidated Financial Statements			5
Cautionary Note Regarding Forward-Looking Statements			19
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			21
Item 3. Quantitative and Qualitative Disclosure About Market Risk			38
Item 4. Controls and Procedures			38
PART II – OTHER INFORMATION
Item 1. Legal Proceedings			39
Item 1A. Risk Factors			39
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			39
Item 6. Exhibits			40
Signatures			42
EX-31.1
EX-31.2
EX-32.1
EX-32.2
EX-101 INSTANCE DOCUMENT
EX-101 SCHEMA DOCUMENT
EX-101 CALCULATION LINKBASE DOCUMENT
EX-101 LABELS LINKBASE DOCUMENT
EX-101 PRESENTATION LINKBASE DOCUMENT
EX-101 DEFINITION LINKBASE DOCUMENT

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

		June 30,				December 31,
		2011				2010
		(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents		$	7,634			$	2,817
Accounts receivable, net of allowance of $673 at June 30, 2011 and $509 at December 31, 2010			92,569				44,354
Inventories, net			18,082				8,182
Prepaid and other current assets			8,904				3,768
Deferred tax assets			755				265
Total current assets			127,944				59,386
Property, plant and equipment, net of accumulated depreciation of $35,217 at June 30, 2011 and $27,712 as of December 31, 2010			152,354				88,395
Other assets:
Goodwill			65,057				60,339
Intangible assets, net of accumulated amortization of $5,679 at June 30, 2011 and $4,498 at December 31, 2010			27,891				5,768
Deposits on equipment under construction			3,535				8,413
Deferred financing costs, net of accumulated amortization of $117 at June 30, 2011 and $506 at December 31, 2010			2,801				3,190
Other noncurrent assets, net			600				597
Total assets		$	380,182			$	226,088
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable		$	40,563			$	13,085
Current portion of long-term debt			—				27,222
Accrued expenses			11,325				8,179
Accrued taxes			649				6,525
Customer advances and deposits			6,469				4,000
Other current liabilities			33				33
Total current liabilities			59,039				59,044
Long-term debt			105,000				44,817
Deferred tax liabilities			39,169				12,058
Deferred income			707				723
Other long-term liabilities			228				—
Total liabilities			204,143				116,642
Stockholders’ equity
Common stock, par value of $.01, 100,000,000 shares authorized, 47,499,074 issued and outstanding			475				475
Additional paid-in capital			82,558				78,288
Retained earnings			93,006				30,683
Total stockholders’ equity			176,039				109,446
Total liabilities and stockholders’ equity		$	380,182			$	226,088

See accompanying notes to consolidated financial statements

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2011				2010				2011				2010
Revenue		$	182,171			$	41,803			$	309,375			$	74,440
Cost of sales			110,068				27,118				180,116				50,294
Gross profit			72,103				14,685				129,259				24,146
Selling, general and administrative expenses			11,703				3,847				20,528				6,715
(Gain)/loss on sale/disposal of assets			17				1,599				(73	)			1,582
Operating income			60,383				9,239				108,804				15,849
Other income (expense):
Interest expense, net			(1,200	)			(6,580	)			(3,158	)			(9,578	)
Loss on early extinguishment of debt			(7,605	)			—				(7,605	)			—
Other income (expense), net			(27	)			(4	)			(39	)			43
Total other expense, net			(8,832	)			(6,584	)			(10,802	)			(9,535	)
Income before income taxes			51,551				2,655				98,002				6,314
Income tax expense			18,313				938				35,679				2,354
Net income		$	33,238			$	1,717			$	62,323			$	3,960
Net income per common share (see Note 1):
Basic		$	0.70			$	0.04			$	1.31			$	0.09
Diluted		$	0.68			$	0.04			$	1.28			$	0.08
Weighted average common shares outstanding:
Basic			47,499				46,323				47,499				46,323
Diluted			48,656				47,972				48,677				47,404

See accompanying notes to consolidated financial statements

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

														Retained
		Common Stock								Additional				Earnings
		Number of				Amount, at				Paid-in				(Accumulated
		Shares				$0.01 par value				Capital				Deficit)				Total
Balance, December 31, 2009			46,323			$	463			$	66,925			$	(1,589	)		$	65,799
Exercise of warrants			1,176				12				10,729				—				10,741
Stock-based compensation			—				—				634				—				634
Net income			—				—				—				32,272				32,272
Balance, December 31, 2010			47,499				475				78,288				30,683				109,446
Stock-based compensation expense*			—				—				4,270				—				4,270
Net income*			—				—				—				62,323				62,323
Balance, June 30, 2011*			47,499			$	475			$	82,558			$	93,006			$	176,039

*      Unaudited

See accompanying notes to consolidated financial statements

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

		Six Months Ended
		June 30,
		2011				2010
Cash flows from operating activities:
Net income		$	62,323			$	3,960
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization			8,987				5,121
Deferred income taxes			22,734				2,022
Provision for doubtful accounts, net of write-offs			135				70
(Gain) loss on sale of assets			(73	)			1,582
Loss on change in fair value of warrant liability			—				6,250
Stock-based compensation expense			4,270				65
Non cash paid in kind interest expense			—				278
Amortization of deferred financing costs			408				303
Write-off of deferred financing costs related to early extinguishment of debt			2,899				—
Net effect of changes in assets and liabilities related to operating accounts			(36,926	)			(2,819	)
Cash provided by operating activities			64,757				16,832
Cash flows from investing activities:
Purchases of and deposits on property and equipment			(65,130	)			(7,071	)
Payments made to acquire Total E&S, Inc., net of cash acquired			(27,225	)			—
Proceeds from sale of property and equipment			2,372				25
Cash used in investing activities			(89,983	)			(7,046	)
Cash flows from financing activities:
Payments on revolving debt, net			(3,100	)			(34,964	)
Proceeds from long-term debt			119,850				65,000
Repayments of long-term debt			(83,789	)			(28,059	)
Repayments of capital lease obligations			—				(27	)
Financing costs			(2,918	)			(2,565	)
Cash provided by (used in) financing activities			30,043				(615	)
Net increase in cash and cash equivalents			4,817				9,171
Cash and cash equivalents, beginning of period			2,817				1,178
Cash and cash equivalents, end of period		$	7,634			$	10,349
Supplemental cash flow disclosure:
Cash paid for interest		$	2,609			$	1,044
Cash paid for taxes		$	18,810			$	238

See accompanying notes to consolidated financial statements

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

Notes to Consolidated Financial Statements
(Unaudited)

Note 1 – Organization, Nature of Business and Summary of Significant Accounting Policies

     C&J Energy Services, Inc. (“C&J”) was incorporated in Texas in 2006 and re-incorporated in Delaware in 2010. C&J is a holding company and substantially all of its operations are conducted through, and substantially all of its assets are held by, C&J Spec-Rent Services, Inc. (“Spec-Rent”) and Total E&S, Inc. (“Total”). C&J owns 100% of the outstanding capital stock of Spec-Rent, an Indiana corporation and, in April 2011, Spec-Rent acquired 100% of the outstanding capital stock of Total, an Indiana corporation. C&J, Spec-Rent and Total are herein collectively referred to as the “Company” and Spec-Rent and Total are herein collectively referred to as the “Subsidiaries.”

     The Company provides hydraulic fracturing, coiled tubing and pressure pumping services to oil and natural gas exploration and production companies operating in basins in South Texas, East Texas/North Louisiana and Western Oklahoma. The Company also manufactures equipment for companies in the energy services industry as well as equipment to fulfill the Company’s internal equipment demands.

     The nature of operations and the regions in which the Company operates are subject to changing economic, regulatory and political conditions. The Company is vulnerable to near-term and long-term changes in the demand for and prices of oil and natural gas and the related demand for oilfield service operations.

Basis of Presentation

     The accompanying consolidated financial statements of the Company have not been audited by the Company’s independent registered public accounting firm, except that the consolidated balance sheet at December 31, 2010 is derived from audited financial statements. In the opinion of management, all adjustments, consisting of normal recurring adjustments, necessary for the fair presentation have been included. In preparing the accompanying consolidated financial statements, management has made certain estimates and assumptions that affect reported amounts in the consolidated financial statements and disclosures of contingencies.

     These consolidated financial statements have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”) for interim financial information. Accordingly, they do not include all of the information and notes required by accounting principles generally accepted in the United States of America (“U.S. GAAP”) for complete financial statements. Therefore, these consolidated financial statements should be read in conjunction with the Company’s audited consolidated financial statements and notes thereto for the year ended December 31, 2010, which are included in the Company’s final prospectus (Registration Statement No. 333-173177) dated July 28, 2011 and filed with the SEC pursuant to Rule 424(b)(4) under the Securities Act (the “Final Prospectus”). The operating results for interim periods are not necessarily indicative of results that may be expected for any other interim period or for the full year.

Principles of Consolidation

     These consolidated financial statements include the accounts of C&J and the Subsidiaries. All significant inter-company transactions and accounts have been eliminated upon consolidation.

Use of Estimates

     The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements
(Unaudited)

contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Estimates are used for, but are not limited to, determining the following: allowance for doubtful accounts, recoverability of long-lived assets and intangibles, useful lives used in depreciation and amortization, income taxes and valuation allowances. The accounting estimates used in the preparation of the consolidated financial statements may change as new events occur, as more experience is acquired, as additional information is obtained and as the Company’s operating environment changes.

Accounts Receivable and Allowance for Doubtful Accounts

     Accounts receivable are stated at the amount billed to customers and are ordinarily due upon receipt. The Company provides an allowance for doubtful accounts, which is based upon a review of outstanding receivables, historical collection information and existing economic conditions. Provisions for doubtful accounts are recorded when it is deemed probable that the customer will not make the required payments at either the contractual due dates or in the future.

Inventories

     Inventories for the Stimulation and Well Intervention Services segment consist of finished goods, including spare parts to be used in maintaining equipment and general supplies and materials for the segment’s operations. Inventories for the Equipment Manufacturing segment consist of manufacturing parts and work-in-process. See Note 8 – Segment Information for further discussion regarding the Company’s reportable segments.

     Inventories are stated at the lower of cost (first-in, first-out basis) or market (net realizable value) and appropriate consideration is given to deterioration, obsolescence and other factors in evaluating net realizable value. Inventory consisted of the following (in thousands):

		June 30,				December 31,
		2011				2010
Manufacturing parts		$	3,257			$	—
Work-in-process			2,459				—
Finished goods			12,712				8,219
			18,428				8,219
Inventory reserve			(346	)			(37	)
		$	18,082			$	8,182

Property, Plant and Equipment

     Property, plant and equipment is recorded at cost less accumulated depreciation. Maintenance and repairs, which do not improve or extend the life of the related assets, are charged to operations when incurred. Refurbishments and renewals are capitalized when the value of the equipment is enhanced for an extended period. When property and equipment are sold or otherwise disposed of, the asset account and related accumulated depreciation account are relieved, and any gain or loss is included in operating income.

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements
(Unaudited)

     The cost of property and equipment currently in service is depreciated over the estimated useful lives of the related assets, which range from three to 25 years. Depreciation is computed on a straight-line basis for financial reporting purposes.

Goodwill, Intangible Assets and Amortization

     Goodwill and other intangible assets with infinite lives are not amortized, but tested for impairment annually or more frequently if circumstances indicate that impairment may exist. Intangible assets with finite useful lives are amortized either on a straight-line basis over the asset’s estimated useful life or on a basis that reflects the pattern in which the economic benefits of the intangible assets are realized. No impairment was recorded in the periods presented herein.

Revenue Recognition

     All revenue is recognized when persuasive evidence of an arrangement exists, the service is complete or the equipment has been delivered to the customer, the amount is fixed or determinable and collectability is reasonably assured, as follows:

     Hydraulic Fracturing Revenue. The Company enters into arrangements with its customers to provide hydraulic fracturing services, which can be either on a spot market basis or under term contracts. The Company only enters into arrangements with customers for which it believes that collectability is reasonably assured. Revenue is recognized and customers are invoiced upon the completion of each job, which can consist of one or numerous fracturing stages. Once a job has been completed to the customer’s satisfaction, a field ticket is written that includes charges for the service performed and the chemicals and proppants consumed during the course of the service. The field ticket also includes charges for the mobilization of the equipment to the location, additional equipment used on the job, if any, and other miscellaneous consumables. Rates for services performed on a spot market basis are based on an agreed-upon hourly spot market rate. With respect to services performed under term contracts, customers are invoiced a monthly mandatory payment based on a specified minimum number of hours of service per month as defined in the contract, whether or not those services are actually utilized, upon the earlier of the passage of time or completion of the job. To the extent customers utilize more than the contracted minimum number of hours of service per month, they are invoiced for such excess at rates defined in the contract upon the completion of each job.

     Coiled Tubing and Pressure Pumping Revenue. The Company enters into arrangements to provide coiled tubing and pressure pumping services to only those customers for which it believes that collectability is reasonably assured. These arrangements are typically short-term in nature and each job can last anywhere from a few hours to multiple days. Coiled tubing and pressure pumping revenue is recognized upon completion of each day’s work based upon a completed field ticket. The field ticket includes charges for the mobilization of the equipment to the location, the service performed, the personnel on the job, additional equipment used on the job, if any, and miscellaneous consumables used throughout the course of the service. The Company typically charges the customer on an hourly basis for these services at agreed upon spot market rates.

     Materials Consumed While Performing Services. The Company generates revenue from chemicals and proppants that are consumed while performing hydraulic fracturing services. The Company charges fees to its customers based on the amount of chemicals and proppants used in providing these services. In addition, ancillary to coiled tubing and pressure pumping revenue, the Company generates revenue from various fluids and supplies that are necessarily consumed during those processes. The Company does not sell or otherwise charge a fee separate and apart from the services it provides for any

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements
(Unaudited)

of the materials consumed while performing hydraulic fracturing, coiled tubing or pressure pumping services.

     Equipment Manufacturing Revenue. The Company enters into arrangements to construct equipment for only those customers for which the Company believes that collectability is reasonably assured. Revenue is recognized and the customer is invoiced upon the completion and delivery of each order to the customer.

Stock-Based Compensation

     The Company accounts for stock-based compensation cost based on grant date fair value by using the Black-Scholes option-pricing model. The Company recognizes stock-based compensation cost on a straight-line basis over the requisite service period. Further information regarding stock-based compensation can be found in Note 5 – Stock-Based Compensation.

Fair Value of Financial Instruments

     The Company’s financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable, accrued warrants, notes payable and long-term debt. The recorded values of cash and cash equivalents, accounts receivable, and accounts payable approximate their fair values based on their short-term nature. The carrying values of notes payable and long-term debt approximate their fair values, as interest approximates market rates. See Note 4 – Fair Value of Financial Instruments for further information regarding fair value of warrants.

Income Taxes

     Income taxes are provided for the tax effects of transactions reported in financial statements and consist of taxes currently due plus deferred taxes. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases.

     Deferred tax assets and liabilities are measured using enacted 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 rates is recognized in income in the period that includes the enactment date. Deferred income tax expense represents the change during the period in the deferred tax assets and deferred tax liabilities.

     The components of the deferred tax assets and liabilities are individually classified as current and non-current based on their characteristics. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized.

Earnings per Share

     Basic earnings per share is based on the weighted average number of ordinary shares outstanding during the applicable period. Diluted earnings per share is computed based on the weighted average number of ordinary shares and ordinary share equivalents outstanding in the applicable period, as if all potentially dilutive securities were converted into ordinary shares (using the treasury stock method).

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements
(Unaudited)

     The following is a reconciliation of the components of the basic and diluted earnings per share calculations for the applicable periods:

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2011				2010				2011				2010
		(In thousands, except per share amounts)
Numerator:
Net income attributed to common shareholders		$	33,238			$	1,717			$	62,323			$	3,960
Denominator:
Weighted average common shares outstanding			47,499				46,323				47,499				46,323
Effect of potentially dilutive common shares:
Warrants and stock options			1,157				1,649				1,178				1,081
Weighted average common shares outstanding and assumed conversions			48,656				47,972				48,677				47,404
Income per common share:
Basic		$	0.70			$	0.04			$	1.31			$	0.09
Diluted		$	0.68			$	0.04			$	1.28			$	0.08
Potentially dilutive securities excluded as anti- dilutive			3,803				—				3,726				324

Recent Accounting Pronouncements

     In December 2010, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“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.

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements
(Unaudited)

Note 2 — Long-Term Debt

     Debt consisted of the following:

		June 30,				December 31,
		2011				2010
Senior Secured Revolving Credit Facility maturing on April 19, 2016		$	105,000			$	—
Senior Secured Credit Facility maturing on June 1, 2013			—				47,039
Subordinated Term Loan maturing on June 30, 2014			—				25,000
			105,000				72,039
Less: amount maturing within one year			—				27,222
Long-term debt		$	105,000			$	44,817

Senior Secured Credit Facility

     On May 28, 2010, the Company entered into a senior credit facility with a financial institution maturing on June 1, 2013 with maximum allowable indebtedness of $126.7 million and principal installments of $2.5 million to be paid monthly, with any remaining balance due at maturity. Under the terms of this facility, interest was payable monthly at a variable interest rate determined from a pricing scale based on debt/EBITDA ratio, with a LIBOR floor of 1.5%. This facility was retired on April 19, 2011 with funds received from the new Credit Facility (as defined below) to pay down remaining principal and accrued interest. The Company wrote off approximately $2.4 million in remaining deferred financing costs associated with the early extinguishment of this facility.

Senior Secured Revolving Credit Facility

     On April 19, 2011, the Company entered into a new five-year $200.0 million senior secured revolving credit agreement (the “Credit Facility”) with Bank of America, N.A., as administrative agent, swing line lender and L/C issuer, Comerica Bank, as L/C issuer and syndication agent, Wells Fargo Bank, National Association, as documentation agent, and various lenders. Obligations under the Credit Facility are guaranteed by the Company’s Subsidiaries. The Credit Facility provides the ability to borrow funds on a revolving basis for working capital needs and also provides for the issuance of letters of credit. In addition, the Company may request additional commitments up to $75.0 million through an incremental facility upon the satisfaction of certain conditions. Up to the entire Credit Facility amount may be drawn as letters of credit, and the Credit Facility has a sublimit of $15.0 million for swing line loans. As of June 30, 2011, $105.0 million was outstanding under the Credit Facility. Subsequently, the Company repaid the entire outstanding balance under the Credit Facility in connection with the IPO and, as such, as of the date of this Form 10-Q, no amounts are outstanding under the Credit Facility leaving the entire $200.0 million available for borrowing.

     Outstanding loans bear interest at either LIBOR or a base rate, at the Company’s election, plus an applicable margin which, prior to the Company’s delivery of a compliance certificate for the three months ended June 30, 2011, was equal to 1.50% for base rate loans and 2.50% for LIBOR loans, and thereafter,

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements
(Unaudited)

the applicable base rate ranges from 1.25% to 2.00% and the applicable LIBOR rate ranges from 2.25% to 3.00% based upon our Leverage Ratio. The Leverage Ratio is the ratio of funded indebtedness to EBITDA for the Company and its Subsidiaries on a consolidated basis. As of June 30, 2011, the weighted average interest rate was 2.8%.

     All obligations under the credit facility are secured, subject to agreed upon exceptions, by a first priority perfected security position on all real and personal property of the Company and its Subsidiaries, as guarantors.

     Voluntary prepayments are permitted under the terms of the Credit Facility at any time without penalty or premium.

     The Credit Facility provides for payment of certain fees and expenses, including (1) a fee on the revolving loan commitments which varies depending on the Company’s Leverage Ratio, (2) a letter of credit fee on the stated amount of issued and undrawn letters of credit and a fronting fee to the issuing lender, and (3) other customary fees, including an agency fee.

     The Credit Facility contains, among other things, restrictions on the Company’s ability to consolidate or merge with other companies, conduct asset sales, incur additional indebtedness, grant liens, issue guarantees, make investments, loans or advances, pay dividends, enter into certain transactions with affiliates and to make capital expenditures in excess of $100.0 million in any fiscal year, provided that up to $50.0 million of such amount in any fiscal year may be rolled over to the subsequent fiscal year and up to $50.0 million of such amount may also be pulled forward from the subsequent fiscal year. In addition, the capital expenditure restrictions do not apply to, among other things, capital expenditures financed solely with proceeds from the issuance of common equity interests or to normal replacement and maintenance capital expenditures.

     The Credit Facility contains customary affirmative covenants including financial reporting, governance and notification requirements. The Credit Facility requires us to maintain, measured on a consolidated basis, (1) an “Interest Coverage Ratio” of not less than 3.00 to 1.00 and (2) a “Leverage Ratio” of not greater than 3.25 to 1.00 as such terms are defined in the Credit Facility. The Company was in compliance with all debt covenants as of June 30, 2011.

     The Credit Facility provides that, upon the occurrence of events of default, obligations thereunder may be accelerated and the lending commitments terminated. Such events of default include, among other things, payment defaults to lenders, failure to meet covenants, material inaccuracies of representations or warranties, cross defaults to other indebtedness, insolvency, bankruptcy, ERISA and judgment defaults, and change in control, which includes (1) a change in control under certain unsecured indebtedness issued by the Company or its Subsidiaries, (2) a person or group other than certain permitted holders becoming the beneficial owner of 35% or more of the Company’s voting securities, or (3) the board of directors being comprised for a period of 18 consecutive months of individuals who were neither members at the beginning of such period nor approved by individuals who were members at the beginning of such period.

     Each loan and issuance of a letter of credit under the Credit Facility is subject to the conditions that the representations and warranties in the loan documents remain true and correct in all material respect and no default or event of default shall have occurred or be continuing at the time of or immediately after such borrowing or extension of a letter of credit.

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements
(Unaudited)

Subordinated Term Loan

     On May 28, 2010, the Company entered into a $25.0 million subordinated term loan with a financial institution maturing on June 30, 2014. Under the term loan, interest was payable monthly at a rate of LIBOR plus 13%, with a LIBOR floor of 1.0%. The term loan was retired on April 19, 2011 using funds received from the new Credit Facility to pay down remaining principal and accrued interest. The Company incurred $4.7 million in early termination penalties as a result of the early extinguishment and wrote off approximately $0.5 million in remaining deferred financing costs.

Note 3 — Derivative Liabilities

     The Derivatives and Hedging topic of the FASB Accounting Standards Codification (“ASC”) 815, establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts. The guidance provides that an entity should use a two-step approach to evaluate whether an equity-linked financial instrument (or embedded feature) is indexed to its own stock, including evaluating the instrument’s contingent exercise and settlement provisions. The topic also indicates that “contracts issued or held by that reporting entity that are both (1) indexed to its own stock and (2) classified in stockholders’ equity in its statement of financial position” should not be considered derivative instruments.

     During 2009, the Company amended and restated the debt agreement associated with an outstanding term loan. In conjunction with this amendment and restatement, the Company executed and delivered a warrant agreement to the lender, whereby the lender (herein referred to as the “Warrant-Holder”) earned warrants over the life of the term loan. Warrants began accumulating in December 2009. The warrants had an exercise price of $0.01 per share and were exercisable upon the settlement of the loan. The term loan was paid in full in October 2010 and the warrants ceased accumulating at that time. The Warrant-Holder had accumulated 1,176,224 warrants as of the date of loan termination and exercised them in full in December 2010.

     Prior to the implementation of the derivatives and hedging topic, the warrants, when issued, would have been classified as permanent equity because they met the exception and all of the criteria in the FASB guidance covering accounting for derivative financial instruments indexed to, and potentially settled in, a company’s own stock. However, the agreements covering these warrants contained an embedded conversion feature such that if the Company made certain equity offerings in the future at a price lower than a price specified in the agreements, additional warrants would be issuable to the Warrant-Holder.

     The derivatives and hedging topic provides that an instrument’s strike price or the number of shares used to calculate the settlement amount are not fixed if its terms provide for any potential adjustment, regardless of the probability of such adjustment or whether such adjustment is in the entity’s control. If the instrument’s strike price or the number of shares used to calculate the settlement amount are not fixed, the instrument (or embedded feature) is considered to be indexed to an entity’s stock if the only variables that could affect the settlement amount would be inputs to the fair value of a “fixed-for-fixed” forward or option on equity shares.

     Under the provisions of the Derivatives and Hedging topic, the embedded conversion feature in the Company’s warrants are not considered indexed to the Company’s stock because future equity offerings (or sales) of the Company’s stock are not an input to the fair value of a “fixed-for-fixed” option on equity shares. Accordingly, as of June 30, 2010, the warrants were recognized as a liability in the Company’s consolidated balance sheet.

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements
(Unaudited)

     The effect of these derivative instruments on the consolidated statements of operations for the six months ended June 30, 2011 and 2010 was as follows (in thousands):

Six Months Ended June 30,

2011

2010

Location of

Amount of Loss

Amount of Loss

Loss Recognized in

Recognized in

Recognized in

Derivative not Designated

Operations on

Operations on

Operations on

as Hedging Instruments

Derivative

Derivative

Derivative

Equity contracts

Interest expense

$

—

$

6,250

Total

$

—

$

6,250

Note 4 — Fair Value of Financial Instruments

     The Company follows the Fair Value Measurements topic of the FASB ASC 820, which defines fair value, establishes a framework for measuring fair value under U.S. GAAP and expands disclosures about fair value measurements. The provisions of this standard apply to other accounting pronouncements that require or permit fair value measurements.

     This guidance defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Hierarchical levels, as defined in this guidance and directly related to the amount of subjectivity associated with the inputs to fair valuations of these assets and liabilities are as follows:

	•		Level 1 - Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities.
	•		Level 2 - Inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly, including quoted prices for similar assets or liabilities in active markets; quoted prices for identical or similar assets or liabilities in markets that are not active; inputs other than quoted prices that are observable for the asset or liability (e.g., interest rates); and inputs that are derived principally from or corroborated by observable market data by correlation or other means.
	•		Level 3 - Inputs that are both significant to the fair value measurement and unobservable. Unobservable inputs reflect the Company’s judgment about assumptions market participants would use in pricing the asset or liability’s estimated impact to quoted prices markets.

     The reported fair values for financial instruments that use Level 3 inputs to determine fair value are based on the Black-Scholes option-pricing model. Accordingly, certain fair values may not represent actual values of our financial instruments that could have been realized during the periods presented.

     For the six months ended June 30, 2010, the Company recorded derivative liabilities on its balance sheet related to the warrants discussed in Note 3 — Derivative Liabilities. The Company used the Black-Scholes option-pricing model to determine the fair value of these warrants using the following

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements
(Unaudited)

assumptions: stock price of $5.85 per share, exercise price of $0.01, risk-free discount rate of 1.59%, volatility of 75% and an expected life of 4.5 years.

     Expected volatilities are based on comparable public company data. The risk-free rate is based on the approximate U.S. Treasury yield rate in effect at the time of valuation. The Company’s calculation of stock price, included in the Black Scholes valuation model, involves the use of different valuation techniques, including a combination of an income and/or market approach. Determination of the fair value is a matter of judgment and often involves the use of significant estimates and assumptions.

     The warrants were exercised in December 2010. The final value of the warrants, upon exercise, was determined based on the value of the underlying common stock included in a private offering of the Company’s common stock that occurred during December 2010 (approximately $10.00 per share).

     A reconciliation of the Company’s liabilities measured at fair value on a recurring basis using significant unobservable inputs (Level 3) is as follows (in thousands):

		Level 3
Balance — December 31, 2009		$	(336	)
Included in earnings as interest expense			(6,250	)
Balance — June 30, 2010		$	(6,586	)

     The Company is not a party to any hedge arrangements, commodity swap agreements or any other derivative financial instruments.

Note 5 — Stock-Based Compensation

     Prior to December 23, 2010, all options granted to the Company’s employees were granted under the C&J Energy Services, Inc. 2006 Stock Option Plan (the “2006 Plan”). The 2006 Plan provided for awards of incentive stock options, non-statutory stock options, restricted stock, and other stock based awards to employees, officers, directors, consultants and advisors. Only non-qualified stock options were awarded under the 2006 Plan. Options awarded under the 2006 Plan generally vested 20% on the date of grant and another 20% on each of the first four anniversaries of the grant date. However, two employees were given fully vested options on the date of grant. On December 23, 2010, the 2006 Plan was amended to provide, among other things, that (1) no additional awards would be granted under the 2006 Plan, (2) all awards outstanding under the 2006 Plan would continue to be subject to the terms of the 2006 Plan, and (3) options to purchase all 237,927 shares awarded under the 2006 Plan would immediately vest and become exercisable in connection with the completion of a private placement of the Company’s common stock that occurred in December 2010.

     On December 23, 2010, the Company adopted the C&J Energy Services, Inc. 2010 Stock Option Plan (the “2010 Plan”). The Company’s 2010 Plan permits the grant of non-statutory stock options and incentive stock options to its employees, consultants and outside directors for up to 5,699,889 shares of common stock. Under the 2010 Plan, option awards are generally granted with an exercise price equal to the market price of the Company’s stock at the date of grant. Those option awards generally vest over three years of continuous service with one-third vesting on the first, second, and third anniversaries of the option’s grant date. Certain option awards provide for accelerated vesting if there is a change in control, as defined in the 2010 Plan.

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements
(Unaudited)

     The fair value of each option award is estimated on the date of grant using the Black-Scholes option-pricing model. Expected volatilities are based on comparable public company data. The Company uses historical data to estimate employee termination and forfeiture rates of the options within the valuation model. The expected term of options granted is derived using the “plain vanilla” method due to the lack of history and volume of option activity at the Company. The risk-free rate is based on the approximate U.S. Treasury yield rate in effect at the time of grant. The Company’s calculation of stock price involves the use of different valuation techniques, including a combination of an income and/or market approach. Determination of the fair value is a matter of judgment and often involves the use of significant estimates and assumptions.

     During the six months ended June 30, 2011, 514,335 options were granted under the 2010 Plan at exercise prices ranging from $10.00 to $15.50 per share. The key input variables used in valuing these options were: risk-free interest of 2.1% to 2.6%; dividend yield of zero; stock price volatility of 75%; and expected option lives of five to six years. No stock options were granted by the Company during the six months ended June 30, 2010.

     As of June 30, 2011, the Company had 5,744,589 options outstanding to employees and nonemployee directors, 1,907,318 of which were issued under the 2006 Plan and the remaining 3,837,271 were issued under the 2010 Plan. As of June 30, 2011 there were 1,862,618 shares available for issuance under the 2010 Plan.

Note 6 — Concentration of Credit Risk

     Financial instruments that potentially subject the Company to concentrations of credit risk consist primarily of cash and cash equivalents and accounts receivable. Concentrations of credit risk with respect to accounts receivable are limited because the Company performs credit evaluations, sets credit limits, and monitors the payment patterns of its customers. Cash balances on deposits with financial institutions, at times, may exceed federally insured limits. The Company monitors the institutions’ financial condition.

Note 7 — Commitments and Contingencies

     The Company has entered into certain take-or-pay contracts that guarantee a minimum level of monthly revenue. The revenue related to these contracts is recognized on the earlier of the passage of time under terms as defined by the respective contract or as the services are performed.

     From time to time, the Company may be involved in claims and litigation arising in the ordinary course of business. Because there are inherent uncertainties in the ultimate outcome of such matters, it is presently not possible to determine the ultimate outcome of any potential claims or litigation against the Company; however, management believes that the outcome of such matters will not have a material adverse effect upon the Company’s consolidated financial position, results of operation or liquidity.

Note 8 — Segment Information

     In accordance with FASB ASC 280 Segment Reporting, the Company routinely evaluates whether or not it has separate operating and reportable segments. Prior to April 2011, the Company determined that it had one operating segment with three related service lines: hydraulic fracturing, coiled tubing and pressure pumping. In reaching this conclusion, management considered the following: (1) the Company’s chief operating decision maker (“CODM”) evaluates performance and makes resource allocation decisions as a single business as opposed to based on discrete service lines, (2) the Company’s business relies on a single infrastructure and uses one labor force that is available to all service lines

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements
(Unaudited)

provided, (3) the Company’s marketing efforts focus on promoting an integrated service package rather than distinct service offerings to discrete customers and (4) the Company’s compensation policy is determined with respect to overall performance rather than the performance of individual services. Each of these factors contributed to management’s conclusion that the Company operated as a single segment prior to April 2011.

     During the second quarter of 2011, the Company reevaluated whether or not it had more than one operating segment and concluded that, with the acquisition of Total in April 2011, it now has two operating and reportable segments: Stimulation and Well Intervention Services and Equipment Manufacturing. This determination was made based on the following factors: (1) the Company’s CODM is currently managing these two segments as separate businesses, evaluating performance and making resource allocation decisions distinctly, and expects to do so for the foreseeable future, and (2) discrete financial information for each segment is available. The following is a brief description of these segments:

     Stimulation and Well Intervention Services. This business segment has three related service lines providing hydraulic fracturing, coiled tubing and pressure pumping services, with a focus on complex, technically demanding well completions.

     Equipment Manufacturing. This business segment constructs equipment, provides equipment repair services and oilfield parts and supplies for the Company’s Stimulation and Well Intervention Services segment as well as for third-party customers in the energy services industry.

     The following tables set forth certain financial information with respect to the Company’s reportable segments. Included in Corporate and Other are intersegment eliminations and costs associated with activities of a general corporate nature. Financial information for the comparable 2010 periods has not been presented because, as previously mentioned, the Company did not have separate operating segments prior to the acquisition of Total in April 2011.

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements
(Unaudited)

		Stimulation and
		Well
		Intervention				Equipment				Corporate and
		Services				Manufacturing				Other				Total
		(in thousands)
Three months ended June 30, 2011
Revenue from external customers		$	177,654			$	4,517			$	—			$	182,171
Inter-segment revenues			—				9,580				(9,580	)			—
Adjusted EBITDA			70,605				2,468				(7,316	)			65,757
Depreciation and amortization			4,534				671				179				5,384
Operating income (loss)			66,081				1,797				(7,495	)			60,383
Capital expenditures			36,344				1,028				(2,026	)			35,346
Six months ended June 30, 2011
Revenue from external customers		$	304,858			$	4,517			$	—			$	309,375
Inter-segment revenues			—				9,580				(9,580	)			—
Adjusted EBITDA			127,139				2,468				(11,928	)			117,679
Depreciation and amortization			7,995				671				321				8,987
Operating income (loss)			119,256				1,797				(12,249	)			108,804
Capital expenditures			65,428				1,028				(1,326	)			65,130
As of June 30, 2011
Identifiable assets		$	329,706			$	46,695			$	3,781			$	380,182

     Management evaluates segment performance and allocates resources based on earnings before net interest expense, income taxes, depreciation and amortization, loss on early extinguishment of debt and the net gain or loss on the disposal of assets (“Adjusted EBITDA”) because Adjusted EBITDA is considered an important measure of each segment’s performance. In addition, management believes that the disclosure of Adjusted EBITDA as a measure of each segment’s operating performance allows investors to make a direct comparison to competitors, without regard to differences in capital and financing structure. Investors should be aware, however, that there are limitations inherent in using Adjusted EBITDA as a measure of overall profitability because it excludes significant expense items. An improving trend in Adjusted EBITDA may not be indicative of an improvement in the Company’s profitability. To compensate for the limitations in utilizing Adjusted EBITDA as operating measures, management also uses U.S. GAAP measures of performance, including operating income and net income, to evaluate performance, but only with respect to the Company as a whole and not on a segment basis.

     As required under Regulation G of the Securities and Exchange Act of 1934, included below is a reconciliation of Adjusted EBITDA (a non-GAAP financial measure) to net income, which is the nearest comparable U.S. GAAP financial measure (in thousands).

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements
(Unaudited)

		Three Months Ended				Six Months Ended
		June 30, 2011				June 30, 2011
Adjusted EBITDA		$	65,757			$	117,679
Interest expense, net			(1,200	)			(3,158	)
Loss on early extinguishment of debt			(7,605	)			(7,605	)
Provision for income taxes			(18,313	)			(35,679	)
Depreciation and amortization			(5,384	)			(8,987	)
Gain (loss) on disposal of assets			(17	)			73
Net income		$	33,238			$	62,323

Note 9 — Subsequent Events

     On July 28, 2011, the Company’s Form S-1 relating to its initial public offering (the “IPO”) of 13,225,000 shares of its common stock was declared effective by the SEC. The IPO closed on August 3, 2011, at which time the Company issued and sold 4,300,000 shares and the selling stockholders named in the Final Prospectus sold 8,925,000 shares, including 1,725,000 shares sold by certain of the selling stockholders pursuant to the full exercise of the underwriters’ option to purchase additional shares. The Company received cash proceeds of approximately $116.0 million from this transaction, net of underwriting discounts and commissions. As of August 26, 2011, approximately $3.1 million in costs associated with this offering had been incurred. These costs, which amounted to $2.2 million as of June 30, 2011, were included in Prepaid and other current assets on the consolidated balance sheet. The Company did not receive any proceeds from the sale of shares by the selling stockholders.

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

     This Quarterly Report on Form 10-Q (this “Form 10-Q”) includes certain “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). Forward-looking statements include those that express a belief, expectation or intention, as well as those that are not statements of historical fact. Forward-looking statements include information regarding our future plans and goals and our current expectations with respect to, among other things:

	•		our future revenues, income and operating performance;
	•		our ability to improve our margins;
	•		operating cash flows and availability of capital;
	•		the timing and success of future acquisitions and other special projects;
	•		future capital expenditures; and
	•		our ability to finance equipment, working capital and capital expenditures.

     Our forward-looking statements are generally accompanied by words such as “estimate,” “project,” “predict,” “believe,” “expect,” “anticipate,” “potential,” “plan,” “goal” or other terms that convey the uncertainty of future events or outcomes. The forward-looking statements in this Form 10-Q speak only as of the date of this report; we disclaim any obligation to update these statements unless required by law, and we caution you not to rely on them unduly. Forward-looking statements are not assurances of future performance and involve risks and uncertainties. We have based these forward-looking statements on our current expectations and assumptions about future events. While our management considers these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks, contingencies and uncertainties, most of which are difficult to predict and many of which are beyond our control. These risks, contingencies and uncertainties include, but are not limited to, the following:

•

a sustained decrease in domestic spending by the oil and natural gas exploration and production industry;

•

a decline in or substantial volatility of crude oil and natural gas commodity prices;

•

delay in or failure of delivery of our new fracturing fleets or future orders of specialized equipment;

•

the loss of or interruption in operations of one or more key suppliers;

•

overcapacity and competition in our industry;

•

the incurrence of significant costs and liabilities in the future resulting from our failure to comply, or our compliance with, new or existing environmental regulations or an accidental release of hazardous substances into the environment;

	•		the loss of, or inability to attract new, key management personnel;
	•		the loss of, or failure to pay amounts when due by, one or more significant customers;

•

unanticipated costs, delays and other difficulties in executing our long-term growth strategy;

•

a shortage of qualified workers;

•

operating hazards inherent in our industry;

•

accidental damage to or malfunction of equipment;

•

an increase in interest rates;

•

the potential inability to comply with the financial and other covenants in our debt agreements as a result of reduced revenues and financial performance or our inability to raise sufficient funds through assets sales or equity issuances should we need to raise funds through such methods;

•

the potential failure to establish and maintain effective internal control over financial reporting; and

•

our inability to operate effectively as a publicly traded company.

     These and other important factors that could affect our operating results and performance are described in (1) “Risk Factors” in Part II, Item 1A of this Form 10-Q, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Part I, Item 2 of this Form 10-Q, and elsewhere within this Form 10-Q, (2) our final prospectus dated July 29, 2011 and filed with the SEC pursuant to Rule 424(b)(4) under the Securities Act (File No. 333-173177) (the “Final Prospectus”), (3) our reports and registration statements filed from time to time with the SEC and (4) other announcements we make from time to time. Should one or more of the risks or uncertainties described above or in this Quarterly Report on Form 10-Q or in the documents incorporated by reference herein occur, or should underlying assumptions prove incorrect, our actual results, performance, achievements or plans could differ materially from those expressed or implied in any forward-looking statements.

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

     The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the unaudited consolidated financial statements and the related notes thereto included elsewhere in this Quarterly Report on Form 10-Q and the audited consolidated financial statements and notes thereto and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for the year ended December 31, 2010 included in our final prospectus (Registration Statement No. 333-173177) dated July 29, 2011 and filed with the SEC pursuant to Rule 424(b)(4) under the Securities Act (the “Final Prospectus”).

     This section contains forward-looking statements that involve risks and uncertainties. Our actual results may differ materially from those discussed in any forward-looking statement because of various factors, including those described in the sections titled “Cautionary Note Regarding Forward-Looking Statements” and “Risk Factors” of this Quarterly Report on Form 10-Q.

Overview

     We are a rapidly growing independent provider of premium hydraulic fracturing and coiled tubing services with a focus on complex, technically demanding well completions. We have historically operated in what we believe to be some of the most geologically challenging basins in South Texas, East Texas/North Louisiana and Western Oklahoma. We are in the process of acquiring additional hydraulic fracturing fleets and are evaluating opportunities with existing and new customers to expand our operations into new areas throughout the United States with similarly demanding completion and stimulation requirements.

     We are a Delaware corporation. Our principal executive offices are located at 10375 Richmond Avenue, Suite 2000, Houston, Texas 77042 and our main telephone number is (713) 260-9900. Our website is available at www.cjenergy.com. We make available free of charge through our website all reports filed with the SEC and all amendments to those reports as soon as reasonably practicable after such material is electronically filed with the SEC. Information available on or through our website is not a part of or incorporated into this or any other report.

How We Generate Our Revenues

     We seek to differentiate our services from those of our competitors by providing customized solutions for our customers’ most challenging well completions. We believe our customers value the experience, technical expertise, high level of customer service and demonstrated operational efficiencies that we bring to projects.

     We have entered into term contracts with EOG Resources (executed April 2010), Penn Virginia (executed May 2010), Anadarko Petroleum (executed August 2010), EXCO Resources (executed August 2010) and Plains Exploration (executed March 2011) for the provision of hydraulic fracturing services. We began service under the Penn Virginia, EOG Resources, Anadarko Petroleum, EXCO Resources and Plains Exploration contracts in July 2010, August 2010, February 2011, April 2011 and August 2011, respectively. Our existing hydraulic fracturing fleets (Fleets 1, 2, 3, 4 and 5) are dedicated through mid-2012, mid-2012, early 2013, mid-2014 and mid-2013, respectively, to producers operating in the Eagle Ford, Haynesville and Granite Wash basins. We are scheduled to take delivery of Fleets 6, 7 and 8 in the fourth quarter of 2011, the first half of 2012 and the second half of 2012, respectively. We are seeking to deploy each of these new fleets under term contracts similar to our existing term contracts.

Our revenues are derived primarily from three sources:

	•		monthly payments for the committed hydraulic fracturing fleets under term contracts as well as prevailing market rates for spot market work, together with associated charges or handling fees for chemicals and proppants that are consumed during the fracturing process;
	•		prevailing market rates for coiled tubing, pressure pumping and other related well stimulation services, together with associated charges for stimulation fluids, nitrogen and coiled tubing materials; and
	•		sales of manufactured equipment, parts and supplies and repair services provided through our recently acquired subsidiary, Total E&S, Inc. (“Total”), a manufacturer of hydraulic fracturing, coiled tubing, pressure pumping and other equipment used in the energy services industry.

     Hydraulic Fracturing. Approximately 80% of our revenues for the six months ended June 30, 2011 were derived from hydraulic fracturing services. Our term contracts generally range from one year to three years. Under the term contacts, our customers are obligated to pay us on a monthly basis for a specified number of hours of service, whether or not those services are actually utilized. To the extent customers utilize more than the specified contract minimums, we will be paid a pre-agreed amount for the provision of such additional services. Our term contracts restrict the ability of the customer to terminate or require our customers to pay us a lump-sum early termination fee, generally representing all or a significant portion of the remaining economic value of the contracts to us.

     Although our term contracts provide us some visibility on anticipated future minimum asset utilization, our term contracts do not provide us with sufficient certainty to present backlog information on an ongoing basis. Unlike long-term contracts for equipment or services at fixed prices or on a day rate or turnkey basis, where future revenue or earnings can be reliably forecasted based on the dollar amount of backlog believed to be firm, future revenues generated from our term contracts are subject to a number of variables that prevent us from providing similar information with any degree of certainty. Under our term contracts, we derive revenues from:

	•		mandatory monthly payments for a specified minimum number of hours of service per month;
	•		pre-agreed amounts for each hour of service in excess of the contracted minimum number of hours of service per month; and
	•		pre-agreed service charges for chemicals and proppant materials that are consumed during the fracturing process.

     Given these variables, revenues from our term contracts vary substantially from customer-to-customer and from month-to-month depending on the number of hours of services actually provided and chemicals and proppant materials consumed. Generally, when we exceed the number of hours of service included in our base monthly rate, we consume more chemicals and proppants and provide additional pumping and related services to complete the project, each of which will significantly impact our revenues. Mandatory monthly payments under our term contracts have historically accounted for less than half of our total revenues.

     Although we have entered into term contracts for each of our hydraulic fracturing fleets, we also have the flexibility to pursue spot market projects. Our term contracts allow us to supplement monthly contract revenue by deploying equipment on short-term spot market jobs on those days when the contract customer does not require our services or is not entitled to our services under the applicable term contract. We charge prevailing market prices per hour for spot market work. We may also charge fees for set up

and mobilization of equipment depending on the job. Generally, these fees and other charges vary depending on the equipment and personnel required for the job and market conditions in the region in which the services are performed. We also source chemicals and proppants that are consumed during the fracturing process and we charge our customers a fee for materials consumed in the process, or we charge our customers a handling fee for chemicals and proppants supplied by the customer. Materials charges reflect the cost of the materials plus a markup and are based on the actual quantity of materials used in the fracturing process. We believe our ability to provide services in the spot market allows us to take advantage of any favorable pricing that may exist in this market and allows us to develop new customer relationships.

     Coiled Tubing and Pressure Pumping. Our coiled tubing, pressure pumping and other related well intervention services are provided in the spot market at prevailing prices per hour. We may also charge fees for set up and mobilization of equipment depending on the job. The set-up charges and hourly rates are determined by a competitive bid process and vary with the type of service to be performed, the equipment and personnel required for the job and market conditions in the region in which the service is performed. We also charge customers for the materials, such as stimulation fluids, nitrogen and coiled tubing materials, that we use in each job. Materials charges reflect the cost of the materials plus a markup and are based on the actual quantity of materials used for the project.

     Equipment Manufacturing. Our equipment manufacturing business constructs equipment primarily for the energy services industry, including hydraulic fracturing pumps, coiled tubing units, pressure pumping units and other equipment. This business also provides equipment repair services and oilfield parts and supplies to the energy services industry.

How We Manage Costs and Maintain Our Equipment

     The principal expenses involved in conducting our business are product and material costs, the costs of acquiring, maintaining and repairing our equipment, labor expenses and fuel costs. Additionally, we incur freight costs to deliver and stage our hydraulic fracturing fleets to the worksite. We maintain and repair all equipment we use in our operations. We primarily purchase our equipment, including engines, transmissions, radiators, motors and pumps, from third-party vendors. Our acquisition of Total in April 2011 has provided us with greater control over the costs of, access to, and delivery of, equipment. Total has historically been one of our largest suppliers of machinery and equipment and is currently constructing the hydraulic fracturing pumps for all three of our on-order fleets. We believe the acquisition of Total provides several strategic advantages, including a significant reduction in our exposure to third-party supply chain constraints, shorter cycle times for the delivery of new equipment and replacement parts, a reduction in and greater control of the cost of new equipment, and enhanced operational control of our service offering. Furthermore, the acquisition of Total is expected to help minimize downtime by enhancing our capabilities for maintenance and repair of our hydraulic fracturing equipment.

     Depreciation costs represented approximately 2.5% and 6.2% of our revenues for the six months ended June 30, 2011 and 2010, respectively. Direct labor costs represented approximately 8.7% and 13.5% of our revenues for the six months ended June 30, 2011 and 2010, respectively. Other costs, including proppant, chemical and freight costs, represented approximately 33.2% and 32.3% of our revenues for the six months ended June 30, 2011 and 2010, respectively. We also incur significant fuel costs in connection with the operation of our hydraulic fracturing fleets and the transportation of our equipment and products.

How We Manage Our Operations

     Our management team uses a variety of tools to monitor and manage our operations in the following four areas: (1) asset utilization, (2) equipment maintenance performance, (3) customer satisfaction and (4) safety performance.

     Asset Utilization. We measure our activity levels by the total number of jobs completed by each of our hydraulic fracturing fleets and coiled tubing units on a monthly basis. By consistently monitoring the activity level, pricing and relative performance of each of our fleets and units, we can more efficiently allocate our personnel and equipment to maximize revenue generation. During the three months ended June 30, 2011, we completed 856 fracturing stages, generated average revenue per fracturing stage of $175,888 and averaged monthly revenue per unit of horsepower of $371. During the first quarter of 2011, we completed 633 fracturing stages, generated average revenue per fracturing stage of $165,717 and averaged monthly revenue per unit of horsepower of $383. Additionally, our hydraulic fracturing fleets were nearly 100% utilized during both the first and second quarters of the year based on available working days per month, which excludes scheduled maintenance days. During the three months ended June 30, 2011, we completed 819 coiled tubing jobs compared to 638 for the first quarter of 2011.

     Equipment Maintenance Performance. Preventative maintenance on our equipment is an important factor in our profitability. If our equipment is not maintained properly, our repair costs may increase and, during periods of high activity, our ability to operate efficiently could be significantly diminished due to having trucks and other equipment out of service. Our maintenance crews perform regular inspections and preventative maintenance on each of our trucks and other mechanical equipment. Our management monitors the performance of our maintenance crews at each of our service centers by reviewing ongoing inspection and maintenance activity and monitoring the level of maintenance expenses as a percentage of revenue. A rising level of maintenance expenses as a percentage of revenue at a particular service center can be an early indication that our preventative maintenance schedule is not being followed. In this situation, management can take corrective measures to help reduce maintenance expenses as well as ensure that maintenance issues do not interfere with operations. Our repair and maintenance costs represented approximately 6.8% and 6.6% of our revenues for the six months ended June 20, 2011 and 2010, respectively.

     Customer Satisfaction. Upon completion of each job, we encourage our customers to provide feedback on their satisfaction level. Customers evaluate our performance under various criteria and comment on their overall satisfaction level. This feedback gives our management valuable information from which to identify performance issues and trends. Our management also uses this information to evaluate our position relative to our competitors in the various markets in which we operate.

     Safety Performance. Maintaining a strong safety record is a critical component of our operational success. Many of our larger customers have safety standards we must satisfy before we can perform services for them. We maintain a safety database so that our customers can review our historical safety record. Our management also uses this safety database to identify negative trends in operational incidents so that appropriate measures can be taken to maintain and enhance our safety standards.

Our Challenges

     We face many challenges and risks in the industry in which we operate. Although many factors contributing to these risks are beyond our ability to control, we continuously monitor these risks, and we have taken steps to mitigate them to the extent practicable. In addition, we believe that we are well positioned to capitalize on the current growth opportunities available in the hydraulic fracturing market. However, we may be unable to capitalize on our competitive strengths to achieve our business objectives and, consequently, our results of operations may be adversely affected. Please read the sections titled “Cautionary Note Regarding Forward-Looking Statements” and “Risk Factors” of this Form 10-Q for additional information about the risks we face.

     Equipment Supply. The overall number of hydraulic fracturing equipment suppliers in the industry in which we operate is limited, and there has historically been high demand for this equipment.

This limited capacity of supply increases the risk of delay and failure to timely deliver both our on-order equipment and any future equipment that may be necessary to grow of our business. We expect to take delivery of three new hydraulic fracturing fleets, Fleets 6, 7 and 8, in the fourth quarter of 2011, in the first half of 2012 and in the second half of 2012, respectively. To mitigate the risk of a potential delay in equipment delivery, we actively monitor the progression of the production schedule of our on-order equipment. Our recent acquisition of Total, a significant supplier of our new on-order hydraulic fracturing equipment, has provided us with added monitoring capabilities and control over access to, and delivery of, new fracturing equipment.

     Hydraulic Fracturing Legislation and Regulation. Legislation has been introduced before Congress in the last few sessions to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process. Although the federal legislation did not pass, if similar federal legislation is introduced and becomes law in the future, the legislation could establish an additional level of regulation that could lead to operational delays or increased operating costs. The federal Environmental Protection Agency (“EPA) also recently proposed rules that would establish new air emission controls for oil and natural gas production and natural gas processing operations. Among other controls, the rules would require operators to use “green completions” for hydraulic fracturing, meaning operators would have to recover rather than vent the gas and natural gas liquids that come to the surface during completion of the fracturing process. In addition, various state and local governments have implemented, or are considering, increased regulatory oversight of hydraulic fracturing, and Texas has adopted legislation that requires disclosure of information regarding the substances used in the hydraulic fracturing process to the Railroad Commission of Texas and the public.

     The adoption of new laws or regulations imposing reporting obligations on, or otherwise limiting or regulating, the hydraulic fracturing process could make it more difficult to complete oil and natural gas wells in shale formations, increase our and our customers’ costs of compliance, and adversely affect the hydraulic fracturing services that we render for our exploration and production customers. In addition, if hydraulic fracturing becomes regulated at the federal level as a result of federal legislation or regulatory initiatives by the EPA, fracturing activities could become subject to additional permitting or regulatory requirements, and also to attendant permitting delays and potential increases in cost, which could adversely affect our business and results of operations.

     Financing Future Growth. Historically, we have funded our growth through bank debt, capital contributions and borrowings from our stockholders, and cash generated from our business. The successful execution of our growth strategy depends on our ability to raise capital as needed to, among other things, finance the purchase of additional hydraulic fracturing fleets. If we are unable to generate sufficient cash flows or to obtain additional capital on favorable terms or at all, we may be unable to sustain or increase our current level of growth in the future. However, we believe we are well positioned to finance our future growth. On April 19, 2011, we entered into a new five-year $200.0 million senior secured revolving credit facility, which increased the amount of funds we are permitted to borrow by $48.3 million and increased the amount of borrowings we can incur in a given fiscal year for capital expenditures by $60.0 million. In addition, our cash flows from operations have continued to increase dramatically, with cash flows from operations during the six months ended June 30, 2011 increasing by $47.9 million from the same period in 2010. We believe that our cash flows from operations and available borrowings under our credit agreement will be sufficient to allow us to sustain or increase our current growth through at least 2012.

Recent Developments

     Initial Public Offering. On July 28, 2011, our registration statement on Form S-1 (File No. 333-173177) relating to the IPO of 13,225,000 shares of our common stock was declared effective by the SEC. The IPO closed on August 3, 2011, at which time we issued and sold 4,300,000 shares and selling stockholders sold 8,925,000 shares, including 1,725,000 shares sold by certain of the selling stockholders pursuant to the full exercise of the underwriters’ option to purchase additional shares, at a price to the

public of $29.00 per share. We received cash proceeds of approximately $116.0 million from this transaction, net of underwriting discounts and commissions. As of August 26, 2011, we had incurred costs of approximately $3.1 million related to the offering. We did not receive any proceeds from the sale of shares by the selling stockholders.

     Acquisition of Total E&S, Inc. On April 28, 2011, we acquired Total, a manufacturer of hydraulic fracturing, coiled tubing, pressure pumping and other equipment used in the energy services industry and one of our largest suppliers of machinery and equipment. Total is constructing the hydraulic fracturing pumps for all three of our on-order fleets. The aggregate purchase price of the acquisition of approximately $33.0 million included $23.0 million in cash to the sellers and $10.0 million in repayment of the outstanding debt and accrued interest of Total. In exchange for the consideration, we acquired net working capital assets with an estimated value of approximately $6.9 million, including $5.4 million in cash and cash equivalents. We funded $25.0 million of the purchase price and debt repayment with borrowings under our credit facility and funded the remainder with cash on hand. Total is an Indiana corporation and is located in Granbury, Texas.

     Following our acquisition of Total, we acquired approximately 10 acres of property adjacent to Total’s current facility and began construction of an approximate 36,000 square feet manufacturing facility. We currently expect our new facility to be operational by December 2011. The total cost of construction of the facility is expected to be approximately $1.6 million. By significantly increasing Total’s manufacturing capacity, we expect to further increase its ability to service us and existing and future third-party customers.

Outlook

     Demand for hydraulic fracturing services has increased significantly over the last two years in the markets in which we operate and we have made substantial investments in the acquisition of additional fracturing fleets in order to capitalize on the market opportunity, which has led to significant growth in our business. We believe the following trends impacting our industry have increased the demand for our services and will continue to support the sustained growth that we have experienced to date:

	•		increased drilling in unconventional resource basins, particularly liquids-rich formations, through the application of horizontal drilling and completion technologies;
	•		improved drilling efficiencies increasing the number of horizontal feet per day requiring completion services;
	•		increased hydraulic fracturing intensity, particularly with increasingly longer laterals and a greater number of fracturing stages, in more demanding and technically complex formations; and
	•		tight supply of hydraulic fracturing equipment resulting from increased attrition of existing equipment and supply chain constraints.

Results of Operations

     Our results of operations are driven primarily by four interrelated variables: (1) drilling and stimulation activities of our customers, (2) the prices we charge for our services, (3) cost of products, materials and labor and (4) our service performance. Because we typically pass the cost of raw materials, such as proppants and chemicals, onto our customers in our term contracts, our profitability is not materially impacted by changes in the costs of these materials. To a large extent, the pricing environment for our services will dictate our level of profitability. To mitigate the volatility in utilization and pricing for the services we offer, we have entered into term contracts covering each of our five existing fleets and intend to do the same with our three on-order hydraulic fracturing fleets.

     In the near term, we expect that our revenues and results of operations will be positively impacted by: (1) the addition and deployment of Fleet 2 in July 2010; (2) the addition and deployment of Fleet 3 in January 2011; (3) the addition and deployment of Fleet 4 in April 2011; (4) the addition and deployment of Fleet 5 in August 2011 and (5) the acquisition of Total in April 2011. We also expect to take delivery of and deploy Fleets 6, 7 and 8 in the fourth quarter of 2011, the first half of 2012 and the second half of 2012, respectively. Each of our fleets is, or is expected to be, deployed under a term contract. We expect that our results of operations in 2011 compared to 2010 will be significantly impacted by the dramatic growth of our asset base over the last twelve months.

Results for the Three Months Ended June 30, 2011 Compared to the Three Months Ended June 30, 2010

     The following table summarizes the change in our results of operations for the three months ended June 30, 2011 when compared to the three months ended June 30, 2010 (in thousands):

		Three Months Ended June 30,
		2011				2010				$ Change
Revenue		$	182,171			$	41,803			$	140,368
Cost of Sales			110,068				27,118				82,950
Gross profit			72,103				14,685				57,418
Selling, general and administrative expenses			11,703				3,847				7,856
Loss on disposal of assets			17				1,599				(1,582	)
Operating income			60,383				9,239				51,144
Other income (expense):
Interest expense, net			(1,200	)			(6,580	)			5,380
Loss on early extinguishment of debt			(7,605	)			—				(7,605	)
Other income (expense), net			(27	)			(4	)			(23	)
Total other expenses, net			(8,832	)			(6,584	)			(2,248	)
Income (loss) before income taxes			51,551				2,655				48,896
Provision (benefit) for income taxes			18,313				938				17,375
Net (loss) income		$	33,238			$	1,717			$	31,521

Revenue

     Revenue increased $140.4 million, or 336%, to $182.2 million for the three months ended June 30, 2011 as compared to $41.8 million for the same period in 2010. This increase was primarily due to the deployment of additional hydraulic fracturing equipment in our Stimulation and Well Intervention Services segment. Fleet 2, which was deployed in the third quarter of 2010, contributed $33.0 million of revenue in the second quarter of 2011; Fleet 3, which was deployed early in the first quarter of 2011, contributed $37.3 million of revenue in the second quarter of 2011; and Fleet 4, which was deployed early in the second quarter of 2011, contributed $28.3 million of revenue in the second quarter of 2011. In addition, we experienced increased utilization of our equipment across all service lines as well as improved pricing for our services. We continued to benefit from increased horizontal drilling and completion-related activity in unconventional resource plays, which enabled us to obtain higher revenues for our hydraulic fracturing services due to the complexity of the work performed in these areas. Our Equipment Manufacturing segment, which we added with the acquisition of Total in April 2011, contributed $4.5 million of revenue during the second quarter of 2011.

Cost of Sales

     Cost of sales increased $83.0 million, or 306%, to $110.1 million for the three months ended June 30, 2011 compared to $27.1 million for the same period in 2010. As a percentage of revenue, cost of sales decreased to 60% for the three months ended June 30, 2011 from 65% for the same period in 2010 due primarily to the significant increase in revenue in the second quarter of 2011 compared to the same period in the prior year.

Selling, General and Administrative Expenses (SG&A)

     SG&A increased $7.9 million, or 204%, to $11.7 million for the three months ended June 30, 2011 as compared to $3.8 million for the same period in 2010. The increase primarily related to $2.7 million in higher payroll and personnel costs associated with the continued hiring of personnel to support our growth and $2.3 million in higher long-term and short-term incentive costs. We also incurred $1.2 million in increased SG&A costs associated with the acquisition of Total in April 2011.

Interest Expense

     Interest expense decreased by $5.4 million, or 82%, to $1.2 million for the three months ended June 30, 2011 as compared to $6.6 million for the same period in 2010. This decrease was due primarily to charges of $4.8 million incurred in the second quarter of 2010 in connection with the change in fair value of our warrant liability. The warrants were exercised in December 2010. Also contributing to the decrease was $0.5 million in lower interest expense due to lower interest rates and $0.1 million in lower amortization of financing costs.

Loss on Early Extinguishment of Debt

     We incurred $7.6 million in costs associated with the early extinguishment of our previous senior credit facility and subordinated term loan during the three months ended June 30, 2011. These costs consisted of $4.7 million in early termination penalties on the subordinated term loan and $2.9 million related to accelerated recognition of deferred financing costs on the previous senior credit facility and subordinated term loan. Immediately following these extinguishments, we entered into a new $200.0 million senior secured revolving credit facility. Please read "—Description of Our Indebtedness” below for further discussion.

Income Taxes

     We recorded a tax provision of $18.3 million for the three months ended June 30, 2011, at an effective rate of 35.5%, compared to a tax provision of $0.9 million for the three months ended June 30, 2010, at an effective rate of 35.3%. The increase was due to our increase in net income.

Results for the Six Months Ended June 30, 2011 Compared to the Six Months Ended June 30, 2010

     The following table summarizes the change in our results of operations for the six months ended June 30, 2011 when compared to the six months ended June 30, 2010 (in thousands):

		Six Months Ended June 30,
		2011				2010				$ Change
Revenue		$	309,375			$	74,440			$	234,935
Cost of Sales			180,116				50,294				129,822
Gross profit			129,259				24,146				105,113
Selling, general and administrative expenses			20,528				6,715				13,813
(Gain)/loss on disposal of assets			(73	)			1,582				(1,655	)
Operating income			108,804				15,849				92,955
Other income (expense):
Interest expense, net			(3,158	)			(9,578	)			6,420
Loss on early extinguishment of debt			(7,605	)			—				(7,605	)
Other income (expense)			(39	)			43				(82	)
Total other expenses			(10,802	)			(9,535	)			(1,267	)
Income (loss) before income taxes			98,002				6,314				91,688
Provision (benefit) for income taxes			35,679				2,354				33,325
Net (loss) income		$	62,323			$	3,960			$	58,363

Revenue

     Revenue increased $234.9 million, or 316%, to $309.4 million for the six months ended June 30, 2011 as compared to $74.4 million for the same period in 2010. This increase was primarily due to the deployment of additional hydraulic fracturing equipment in our Stimulation and Well Intervention Services segment. Fleet 2, which was deployed in the third quarter of 2010, contributed $62.4 million of revenue in the six months ended June 30, 2011; Fleet 3, which was deployed early in the first quarter of 2011, contributed $65.5 million of revenue in the six months ended June 30, 2011; and Fleet 4, which was deployed early in the second quarter of 2011, contributed $28.3 million of revenue in the six months ended June 30, 2011. In addition, we experienced increased utilization of our equipment across all service lines as well as improved pricing for our services. We continued to benefit from increased horizontal drilling and completion-related activity in unconventional resource plays, which enabled us to obtain higher revenues for our hydraulic fracturing services due to the complexity of the work performed in these areas. Our Equipment Manufacturing segment, which we added with the acquisition of Total in April 2011, contributed $4.5 million of revenue during the first half of 2011.

Cost of Sales

     Cost of sales increased $129.8 million, or 258%, to $180.1 million for the six months ended June 30, 2011 as compared to $50.3 million for the same period in 2010. As a percentage of revenue, cost of sales decreased to 58% for the six months ended June 30, 2011 from 68% for the same period in 2010 due primarily to the significant increase in our revenues from 2010 to 2011.

Selling, General and Administrative Expenses (SG&A)

     SG&A increased $13.8 million, or 206%, to $20.5 million for the six months ended June 30, 2011 as compared to $6.7 million for the same period in 2010. The increase primarily related to $4.8 million in higher long-term and short-term incentive costs and $4.5 million in higher payroll and personnel costs associated with the continued hiring of personnel to support our growth. We also incurred $1.2 million in increased SG&A costs associated with the acquisition of Total and $0.5 million in increased professional fees.

Interest Expense

     Interest expense decreased by $6.4 million, or 67%, to $3.2 million for the six months ended June 30, 2011 as compared to $9.6 million for the same period in 2010. This decrease was due primarily to charges of $6.3 million incurred in the six months ended June 30, 2010 in connection with the change in fair value of our warrant liability. The warrants were exercised in December 2010.

Loss on Early Extinguishment of Debt

     We incurred $7.6 million in costs associated with the early extinguishment of our previous senior credit facility and subordinated term loan during the six months ended June 30, 2011. These costs consisted of $4.7 million in early termination penalties on the subordinated term loan and $2.9 million related to accelerated recognition of deferred financing costs on the previous senior credit facility and subordinated term loan. Immediately following these extinguishments, we entered into a new $200.0 million senior secured revolving credit facility. Please read “—Description of Our Indebtedness” below for further discussion.

Income Taxes

     We recorded a tax provision of $35.7 million for the six months ended June 30, 2011, at an effective rate of 36.4%, compared to a tax provision of $2.4 million for the six months ended June 30, 2010, at an effective rate of 37.3%. The increase was due to our increase in net income.

Liquidity and Capital Resources

     Our primary sources of liquidity to date have been capital contributions and borrowings from stockholders, borrowings under our credit facilities and cash flows from operations. Our primary use of capital has been the acquisition and maintenance of equipment. During 2009, we spent significantly less on capital expenditures than we had in previous years. Our capital expenditures increased in 2010 and we anticipate capital expenditures will continue to increase through 2012. We have ordered three new hydraulic fracturing fleets, Fleets 6, 7 and 8, which are scheduled for delivery in the fourth quarter of 2011, the first half of 2012 and the second half of 2012, respectively. Fleet 6 has an aggregate cost of approximately $33 million, of which approximately $1.9 million had been funded as of August 26, 2011. Fleet 7 has an aggregate cost of approximately $26 million, of which approximately $1.0 million had been funded as of August 26, 2011; and Fleet 8 has an aggregate cost of approximately $26 million, of which approximately $0.6 million had been funded as of August 26, 2011. We intend to fund Fleets 6, 7 and 8 through a combination of cash flows from operations, proceeds from our IPO and borrowings under our credit facility.

     On April 19, 2011, we entered into a five-year $200.0 million revolving credit facility, which we refer to as the credit facility. Proceeds from the closing of the credit facility were used to repay $49.6 million of indebtedness outstanding under our previous revolving credit facility and $29.9 million of indebtedness, accrued interest and early termination penalties under our subordinated term loan. The majority of proceeds we received from our IPO were used to pay down all amounts outstanding under our credit facility and, as such, we have no balance outstanding as of August 26, 2011.

     We continually monitor potential capital sources, including equity and debt financings, in order to meet our planned capital expenditures and liquidity requirements. Our ability to fund operating cash flow shortfalls, if any, and to fund planned 2011 and 2012 capital expenditures will depend upon our future operating performance, and more broadly, on the availability of equity and debt financing, which will be affected by prevailing economic conditions in our industry and financial, business and other factors, some of which are beyond our control. Based on our existing operating performance, we believe our cash flows and existing capital coupled with borrowings available under our credit facility will be adequate to meet operational and capital expenditure needs for the next 12 months.

     Our credit facility contains covenants that require us to maintain an interest coverage ratio, to maintain a Leverage Ratio and to satisfy certain other conditions. These covenants are subject to a number of exceptions and qualifications set forth in the credit agreement that evidences such credit facility. We are currently in compliance with these covenants. Please read “Description of Our Indebtedness” elsewhere in this Form 10-Q. In addition, our credit facility contains covenants that limit our ability to make capital expenditures in excess of $100.0 million in any fiscal year, provided that up to $50.0 million of such amount in any fiscal year may be rolled over to the subsequent fiscal year, and up to $50.0 million of such amount may also be pulled forward from the subsequent fiscal year. The capital expenditure restrictions do not apply to capital expenditures financed with proceeds from the issuance of common equity interests or to maintenance capital expenditures. The credit facility also restricts our ability to incur additional debt or sell assets, make certain investments, loans and acquisitions, guarantee debt, grant liens, enter into transactions with affiliates, engage in other lines of business and pay dividends and distributions.

Capital Requirements

     The energy services business is capital-intensive, requiring significant investment to expand, upgrade and maintain equipment. Our capital requirements have consisted primarily of, and we anticipate will continue to be:

	•		growth capital expenditures, such as those to acquire additional equipment and other assets or upgrade existing equipment to grow our business; and
	•		maintenance capital expenditures, which are capital expenditures made to extend the useful life of partially or fully depreciated assets.

     We continually monitor new advances in hydraulic fracturing equipment and down-hole technology, as well as technologies that may complement our existing businesses, and commit capital funds to upgrade and purchase additional equipment to meet our customers’ needs. Assuming the timely delivery of Fleet 6 in the fourth quarter of 2011, we expect our total 2011 capital expenditures to be approximately $120 million, of which $80.7 million has been spent as of August 26, 2011. The remainder of capital expenditures for 2011 include the purchase of Fleet 6, three new coil tubing units, and maintenance capital expenditures.

     Historically, we have grown through organic expansion. We plan to continue to monitor the economic environment and demand for our services and adjust our business strategy as necessary.

Financial Condition and Cash Flows

     The net cash provided by or used in our operating, investing and financing activities is summarized below (in thousands):

		Six Months Ended June 30,
		2011				2010
Cash flow provided by (used in):
Operating activities		$	64,757			$	16,832
Investing activities			(89,983	)			(7,046	)
Financing activities			30,043				(615	)
Change in cash and cash equivalents		$	4,817			$	9,171

Cash Provided by Operating Activities

     Net cash provided by operating activities increased $47.9 million for the six months ended June 30, 2011 as compared to the same period in 2010. This increase was primarily due to higher net income and deferred tax expense, partially offset by a decrease related to working capital changes related to accounts receivable, accounts payable and income taxes payable. Accounts receivable and accounts payable were both higher due to the increase in our activity levels. Income taxes payable were lower due to substantial payments made in June 2011 for federal income tax purposes.

Cash Flows Used in Investing Activities

     Net cash used in investing activities increased $82.9 million for the six months ended June 30, 2011 as compared to the same period in 2010. This increase was due primarily to higher capital expenditures related to the growth of our hydraulic fracturing services business, which doubled in size from two fleets at the end of 2010 to four fleets early in the second quarter of 2011. For the six months ended June 30, 2011 we spent $48.9 million related to our hydraulic fracturing fleet expansion. Cash used in investing activities also increased during 2011 by $27.2 million as a result of our acquisition of Total.

Cash Flows Provided by (Used in) Financing Activities

     Net cash provided by financing activities was $30.0 million for the six months ended June 30, 2011 as compared to net cash used in financing activities of $0.6 million for the same period in 2010. The increase was primarily due to net borrowings under our credit facility during the first half of 2011 to fund our capital spending program and the acquisition of Total.

Off-Balance Sheet Arrangements

     We had no off-balance sheet arrangements, as defined in Item 303(a)(4)(ii) of Regulation S-K, as of June 30, 2011.

Description of Our Indebtedness

     Senior Secured Credit Agreement. On April 19, 2011, we entered into a new five-year $200.0 million senior secured revolving credit agreement with Bank of America, N.A., as administrative agent, swing line lender and L/C issuer, Comerica Bank, as L/C issuer and syndication agent, Wells Fargo Bank, National Association, as documentation agent, and various lenders. Our obligations under our credit facility are guaranteed by our subsidiaries C&J Spec-Rent Services, Inc. and Total (the “Subsidiaries”). Our credit facility enables us to borrow funds on a revolving basis for working capital needs and also provides for the issuance of letters of credit. In addition, we may request additional commitments of up to $75.0 million through an incremental facility upon the satisfaction of certain conditions. Up to the entire credit facility amount may be drawn as letters of credit, and the credit facility has a sublimit of $15.0 million for swing line loans. Currently, there are not amounts outstanding under our credit facility, leaving the entire $200.0 million available for borrowing.

     Loans under our credit facility are denominated in U.S. dollars and will mature on April 19, 2016. Outstanding loans bear interest at either LIBOR or a base rate, at our election, plus an applicable margin which, prior to our delivery of a compliance certificate for the quarter ended June 30, 2011, was equal to 1.50% for base rate loans and 2.50% for LIBOR loans. Thereafter, the applicable base rate ranges from 1.25% to 2.00% and the applicable LIBOR rate ranges from 2.25% to 3.00% based upon our Leverage Ratio. The Leverage Ratio is the ratio of funded indebtedness to EBITDA for us and our subsidiaries on a consolidated basis. As of June 30, 2011, the weighted average interest rate under our credit facility was 2.8%.

     All obligations under our credit facility are secured, subject to agreed upon exceptions, by a first priority perfected security position on all real and personal property of us and our Subsidiaries, as guarantors.

     Voluntary prepayments are permitted under the terms of our credit facility at any time without penalty or premium.

     Our credit facility provides for payment of certain fees and expenses, including (1) a fee on the revolving loan commitments which varies depending on our Leverage Ratio, (2) a letter of credit fee on the stated amount of issued and undrawn letters of credit and a fronting fee to the issuing lender, and (3) other customary fees, including an agency fee.

     Our credit facility contains, among other things, restrictions on our and our guarantors’ ability to consolidate or merge with other companies, conduct asset sales, incur additional indebtedness, grant liens, issue guarantees, make investments, loans or advances, pay dividends, enter into certain transactions with affiliates and to make capital expenditures in excess of $100.0 million in any fiscal year, provided that up to $50.0 million of such amount in any fiscal year may be rolled over to the subsequent fiscal year and up to $50.0 million of such amount may also be pulled forward from the subsequent fiscal year. The capital expenditure restrictions do not apply to, among other things, capital expenditures financed solely with proceeds from the issuance of common equity interests or to normal replacement and maintenance capital expenditures.

     Our credit facility contains customary affirmative covenants including financial reporting, governance and notification requirements. Our credit facility requires us to maintain, measured on a consolidated basis, (1) an “Interest Coverage Ratio” of not less than 3.00 to 1.00 and (2) a “Leverage Ratio” of not greater than 3.25 to 1.00 as such terms are defined in our credit facility. We are currently in compliance with all debt covenants.

     Our credit facility provides that, upon the occurrence of events of default, our obligations thereunder may be accelerated and the lending commitments terminated. Such events of default include, among other things, payment defaults to lenders, failure to meet covenants, material inaccuracies of representations or warranties, cross defaults to other indebtedness, insolvency, bankruptcy, ERISA and judgment defaults, and change in control, which includes (1) a change in control under certain unsecured indebtedness issued by us or our Subsidiaries, (2) a person or group other than certain permitted holders becoming the beneficial owner of 35% or more of our voting securities, or (3) our board of directors being comprised for a period of 18 consecutive months of individuals who were neither members at the beginning of such period nor approved by individuals who were members at the beginning of such period.

     Each loan and issuance of a letter of credit under the credit facility is subject to the conditions that the representations and warranties in the loan documents remain true and correct in all material respects and no default or event of default shall have occurred or be continuing at the time of or immediately after such borrowing or extension of a letter of credit.

Critical Accounting Policies

     The selection and application of accounting policies is an important process that has developed as our business activities have evolved and as the accounting standards have developed. Accounting standards generally do not involve a selection among alternatives, but involve the implementation and interpretation of existing standards, and the use of judgment applied to the specific set of circumstances existing in our business. We make every effort to properly comply with all applicable standards on or before their adoption, and we believe the proper implementation and consistent application of the accounting standards are critical.

     Our discussion and analysis of our financial condition and results of operations is based upon our consolidated financial statements, which have been prepared in accordance with U.S. GAAP. The preparation of these consolidated financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, expenses and related disclosures. We base our estimates and assumptions on historical experience and on various other factors that we believe to be reasonable under the circumstances. We evaluate our estimates and assumptions on an ongoing basis. The results of our analysis form the basis for making assumptions about the carrying values of assets and liabilities that are not readily apparent from other sources. Our actual results may differ from these estimates under different assumptions or conditions.

     We believe the following critical accounting policies involve significant areas of management’s judgments and estimates in the preparation of our consolidated financial statements.

     Property, Plant and Equipment. Property, plant and equipment is recorded at cost less accumulated depreciation. Maintenance and repairs, which do not improve or extend the life of the related assets, are charged to operations when incurred. Refurbishments and renewals are capitalized when the value of the equipment is enhanced for an extended period. When property and equipment are sold or otherwise disposed of, the asset account and related accumulated depreciation account are relieved, and any gain or loss is included in operating income. The cost of property and equipment currently in service is depreciated over the estimated useful lives of the related assets, which range from three to 25 years. Depreciation is computed on a straight-line basis for financial reporting purposes. Depreciation expense charged to operations was $4.3 million and $2.2 million for the three months ended June 30, 2011 and 2010, respectively. Depreciation expense was $7.5 million and $4.4 million for the six months ended June 30, 2011 and 2010, respectively.

     Goodwill, Intangible Assets and Amortization. Goodwill and other intangible assets with infinite lives are not amortized, but tested for impairment annually or more frequently if circumstances indicate that impairment may exist. Intangible assets with finite useful lives are amortized either on a straight-line basis over the asset’s estimated useful life or on a basis that reflects the pattern in which the economic benefits of the intangible assets are realized. The impairment test requires the allocation of goodwill and all other assets and liabilities to reporting units. We perform impairment tests on the carrying value of goodwill for each of our reporting units at least annually. Our annual impairment tests involve the use of different valuation techniques, including a combination of the income and market approach, to determine the fair value of each reporting unit. Determining the fair value of a reporting unit is a matter of judgment and often involves the use of significant estimates and assumptions. If the fair value of the reporting unit is less than its carrying value, an impairment loss is recorded to the extent that the implied fair value of the reporting unit’s goodwill is less than its carrying value. For the six months ended June 30, 2011 and 2010, there were no indicators of impairment. Significant and unanticipated changes to these assumptions could require an additional provision for impairment in a future period.

     Impairment of Long-Lived Assets. We assess the impairment of our long-lived assets whenever events or changes in circumstances indicate that the carrying value may not be recoverable. Such indicators include changes in our business plans, a change in the physical condition of a long-lived asset or the extent or manner in which it is being used, or a severe or sustained downturn in the oil and natural gas industry.

     Recoverability is assessed by using undiscounted future net cash flows of assets grouped at the lowest level for which there are identifiable cash flows independent of the cash flows of other groups of assets. If the undiscounted future net cash flows are less than the carrying amount of the asset, the asset is deemed impaired. The amount of the impairment is measured as the difference between the carrying value and the fair value of the asset.

     We make estimates and judgments about future undiscounted cash flows and fair values. Although our cash flow forecasts are based on assumptions that are consistent with our plans, there is a

significant degree of judgment involved in determining the cash flows attributable to a long-lived asset over its estimated remaining useful life. Our estimates of anticipated cash flows could be reduced significantly in the future and as a result, the carrying amounts of our long-lived assets could be subject to impairment charges in the future.

     Revenue Recognition. All revenue is recognized when persuasive evidence of an arrangement exists, the service is complete or the equipment has been delivered to the customer, the amount is fixed or determinable and collectability is reasonably assured, as follows:

     Hydraulic Fracturing Revenue. We enter into arrangements with our customers to provide hydraulic fracturing services, which can be either on a spot market basis or under term contracts. We only enter into arrangements with customers for which we believe that collectability is reasonably assured. Revenue is recognized and customers are invoiced upon the completion of each job, which can consist of one or numerous fracturing stages. Once a job has been completed to the customer’s satisfaction, a field ticket is written that includes charges for the service performed and the chemicals and proppants consumed during the course of the service. The field ticket also includes charges for the mobilization of the equipment to the location, additional equipment used on the job, if any, and other miscellaneous consumables. Rates for services performed on a spot market basis are based on an agreed-upon hourly spot market rate. With respect to services performed under term contracts, customers are invoiced a monthly mandatory payment based on a specified minimum number of hours of service per month as defined in the contract, whether or not those services are actually utilized, upon the earlier of the passage of time or completion of the job. To the extent customers utilize more than the contracted minimum number of hours of service per month, they are invoiced for such excess at rates defined in the contract upon the completion of each job.

     Coiled Tubing and Pressure Pumping Revenue. We enter into arrangements to provide coiled tubing and pressure pumping services to only those customers for which we believe that collectability is reasonably assured. These arrangements are typically short-term in nature and each job can last anywhere from a few hours to multiple days. Coiled tubing and pressure pumping revenue is recognized upon completion of each day’s work based upon a completed field ticket. The field ticket includes charges for the mobilization of the equipment to the location, the service performed, the personnel on the job, additional equipment used on the job, if any, and miscellaneous consumables used throughout the course of the service. We typically charge the customer on an hourly basis for these services at agreed upon spot market rates.

     Materials Consumed While Performing Services. We generate revenue from chemicals and proppants that are consumed while performing hydraulic fracturing services. We charge fees to our customers based on the amount of chemicals and proppants used in providing these services. In addition, ancillary to coiled tubing and pressure pumping revenue, we generate revenue from various fluids and supplies that are necessarily consumed during those processes. We do not sell or otherwise charge a fee separate and apart from the services we provide for any of the materials consumed while performing hydraulic fracturing, coiled tubing or pressure pumping services.

     Equipment Manufacturing Revenue. We enter into arrangements to construct equipment for only those customers for which the Company believes that collectability is reasonably assured. Revenue is recognized and the customer is invoiced upon the completion and delivery of each order to the customer.

     Accounts Receivable and Allowance for Doubtful Accounts. Accounts receivable are stated at the amount billed to customers and are ordinarily due upon receipt. We provide an allowance for doubtful accounts, which is based upon a review of outstanding receivables, historical collection information and existing economic conditions. Provisions for doubtful accounts are recorded when it is deemed probable that the customer will not make the required payments at either contractual due dates or in the future. The allowance for doubtful accounts totaled $0.7 million at June 30, 2011 and $0.5 million at December 31,

2010. Bad debt expense was $70,000 and $57,500 for the three months ended June 30, 2011 and 2010, respectively, and $137,500 and $70,000 for the six months ended June 30, 2011 and 2010, respectively.

     Stock-Based Compensation. We recognize compensation expense related to stock-based awards, based on the grant date estimated fair value. We amortize the fair value of stock options on a straight-line basis over the requisite service period of the award, which is generally the vesting period. The determination of the fair value of stock options was estimated using the Black-Scholes option-pricing model and required the use of highly subjective assumptions. The Black-Scholes option-pricing model requires inputs such as the expected term of the grant, expected volatility and risk-free interest rate. Further, the forfeiture rate also affects the amount of aggregate compensation that we are required to record as an expense.

     We estimate our forfeiture rate based on an analysis of our actual forfeitures and will continue to evaluate the appropriateness of the forfeiture rate based on actual forfeiture experience, analysis of employee turnover and other factors. Quarterly changes in the estimated forfeiture rate can have a significant effect on reported stock-based compensation expense, as the cumulative effect of adjusting the rate for all expense amortization is recognized in the period the forfeiture estimate is changed. If a revised forfeiture rate is higher than the previously estimated forfeiture rate, an adjustment is made that will result in a decrease to the stock-based compensation expense recognized in the consolidated financial statements. If a revised forfeiture rate is lower than the previously estimated forfeiture rate, an adjustment is made that will result in an increase to the stock-based compensation expense recognized in the consolidated financial statements.

     We will continue to use judgment in evaluating the expected term, volatility and forfeiture rate related to our stock-based compensation on a prospective basis and will incorporate these factors into our option-pricing model.

     Each of these inputs is subjective and generally requires significant management judgment. If, in the future, we determine that another method for calculating the fair value of our stock options is more reasonable, or if another method for calculating these input assumptions is prescribed by authoritative guidance, and, therefore, should be used to estimate expected volatility or expected term, the fair value calculated for our employee stock options could change significantly. Higher volatility and longer expected terms generally result in an increase to stock-based compensation expense determined at the date of grant.

     Income Taxes. Income taxes are provided for the tax effects of transactions reported in financial statements and consist of taxes currently due plus deferred taxes. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases.

     Deferred tax assets and liabilities are measured using enacted 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 rates is recognized in income in the period that includes the enactment date.

     Deferred income tax expense represents the change during the period in the deferred tax assets and deferred tax liabilities.

     The components of the deferred tax assets and liabilities are individually classified as current and non-current based on their characteristics. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized.

     Effective January 1, 2009, we adopted guidance issued by the Financial Accounting Standards Board Accounting Standards Codification (“FASB ASC”) Topic 740, Income Taxes, in accounting for uncertainty in income taxes. This guidance clarifies the accounting for income taxes by prescribing the minimum recognition threshold an income tax position is required to meet before being recognized in the financial statements and applies to all income tax positions. Each income tax position is assessed using a two step process. A determination is first made as to whether it is more likely than not that the income tax position will be sustained, based upon technical merits, upon examination by the taxing authorities. If the income tax position is expected to meet the more likely than not criteria, the benefit recorded in the financial statements equals the largest amount that is greater than 50% likely to be realized upon its ultimate settlement. We did not recognize any uncertain tax positions upon adoption of the guidance and had no uncertain tax positions as of June 30, 2011, and December 31, 2010. Management believes there are no tax positions taken or expected to be taken in the next twelve months that would significantly change our unrecognized tax benefits.

     We will record income tax related interest and penalties, if applicable, as a component of the provision for income tax expense. However, there were no amounts recognized relating to interest and penalties in the consolidated statements of operations for the three and six months ended June 30, 2011, and 2010, respectively. The tax years that remain open to examination by the major taxing jurisdictions to which we are subject range from 2007 to 2010. We have identified our major taxing jurisdictions as the United States of America and Texas. None of our federal or state tax returns are currently under examination.

     We are subject to the Texas Margin Tax, which is determined by applying a tax rate to a base that considers both revenue and expenses. It is considered an income tax and is accounted for in accordance with the provisions of the FASB ASC Topic 740, Income Taxes.

Recently Adopted Accounting Pronouncements

     In December 2010, the FASB issued ASU No. 2010-09, “Business Combinations: Disclosure of Supplementary Pro Forma Information for Business Combinations” or ASU 2010-29. ASU 2010-29 addresses diversity in the interpretation of 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 our financial position, results of operations or cash flows.

Item 3. Quantitative and Qualitative Disclosure About Market Risk

     There have been no material changes in market risk from the information provided in “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Quantitative and Qualitative Disclosures About Market Risk” in the Final Prospectus.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

     We maintain disclosure controls and procedures that are designed to provide reasonable assurance that the information required to be disclosed by us in our 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 that such information is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure.

     As required by Rule 13a-15(b) under the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this Form 10-Q. Based upon that evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of June 30, 2011.

Changes in Internal Control over Financial Reporting

     No changes in our system of internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) occurred during the quarterly period ended June 30, 2011 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

     We are subject to various legal proceedings and claims incidental to or arising in the ordinary course of our business. Our management does not expect the outcome in any of these known legal proceedings, individually or collectively, to have a material adverse effect on our consolidated financial condition or results of operations.

Item 1A. Risk Factors

     

     In addition to the information set forth in this Form 10-Q, including under the section titled “Cautionary Note Regarding Forward-Looking Statements,” please see the information set forth under “Risk Factors” of the Final Prospectus for a detailed discussion of the risk factors affecting us. As of the date of this Form 10-Q, there have been no material changes to the risk factors disclosed in the Final Prospectus.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

(a) Sales of Unregistered Securities

     On July 14, 2011, we issued and sold an aggregate of 87,500 shares of our common stock to our Chief Financial Officer at a price of $1.43 per share for a total of approximately $0.1 million upon his exercise of options previously granted to him under the C&J Energy Services, Inc.’s 2006 Stock Option Plan. No underwriters were involved in this sale of securities. This sale of securities was made in reliance upon the exemption from the registration requirements contained in Rule 701 promulgated under Section 3(b) of the Securities Act, as transactions pursuant to compensatory benefit plans and contracts relating to compensation.

(b) Use of Proceeds from Public Offering of Common Stock

     Our IPO of common stock was effected through a Registration Statement on Form S-1 (File No. 333-173177), which was declared effective by the SEC on July 28, 2011. Goldman, Sachs & Co., J.P. Morgan Securities LLC, Citigroup Global Markets Inc., Wells Fargo Securities, LLC, Simmons & Company International and Tudor, Pickering, Holt & Co. Securities, Inc. acted as underwriters for the offering. Goldman, Sachs & Co., J.P. Morgan Securities LLC and Citigroup Global Markets Inc. acted as the co-managers for the offering. Under the Form S-1, we registered the offer and sale of an aggregate of 13,225,000 shares of our common stock, 4,300,000 shares of which were issued and sold by us and 8,925,000 shares of which were sold by the selling stockholders named in the Form S-1, including 1,725,000 shares sold by certain of the selling stockholders pursuant to the full exercise of the underwriters’ option to purchase additional shares. The IPO closed on August 3, 2011, and at that time we issued and sold all of the shares that were registered.

     The shares were sold at a price to the public of $29.00 per share and we received cash proceeds of approximately $116.0 million from this transaction, net of underwriting discounts and commissions. We did not receive any proceeds from the sale of shares by the selling stockholders. We paid to the underwriters underwriting discounts and commissions totaling approximately $8.7 million, and we incurred additional costs of approximately $3.1 million in connection with the offering, which amounted to total fees and costs of approximately $11.8 million. Thus, the net offering proceeds to us, after deducting underwriting discounts and commissions and offering costs, were approximately $113.0 million. No offering costs were paid directly or indirectly to any of our directors or officers (or their associates) or persons owning 10% or more of any class of our equity securities or to any other affiliates, other than reimbursement of legal expenses for selling stockholders.

     We used $105.0 million of the net proceeds that we received from the IPO to repay all outstanding indebtedness under our credit facility; we used the remaining $8.0 million in net proceeds to partially fund the purchase price of our three on-order hydraulic fracturing fleets.

Item 6. Exhibits

     The exhibits required to be filed or furnished by Item 601 of Regulation S-K are listed below.

1.1		Underwriting Agreement, dated July 28, 2011, by and among C&J Energy Services, Inc., C&J Spec Rent Services, Inc., Total E&S, Inc., the Selling Stockholders named therein and Goldman, Sachs & Co. and J.P. Morgan Securities LLC (incorporated herein by reference to Exhibit 1.1 to the C&J Energy Services, Inc.’s Current Report on Form 8-K, filed on August 3, 2011 (File No. 001-35255))
3.1		Amended and Restated Certificate of Incorporation of C&J Energy Services, Inc. (incorporated herein by reference to Exhibit 3.1 to the C&J Energy Services, Inc’s Registration Statement on Form S-1, dated March 30, 2011 (Registration No. 333-173177))
3.2		Amended and Restated Bylaws of C&J Energy Services, Inc. (incorporated herein by reference to Exhibit 3.1 to the C&J Energy Services, Inc’s Registration Statement on Form S-1, dated March 30, 2011 (Registration No. 333-173177))
10.1		Credit Agreement, dated as of April 19, 2011, among C&J Energy Services, Inc. as Borrower, Bank of America, N.A. as Administrative Agent, Swing Line Lender and L/C Issuer, Comerica Bank as L/C Issuer and Syndication Agent, Wells Fargo Bank, National Association as Documentation Agent, and the Other Lenders party thereto (incorporated herein by reference to Exhibit 10.18 to Amendment No. 1 to the C&J Energy Services, Inc.’s Registration Statement on Form S-1/A, dated May 12, 2011 (Registration No. 333-173177))
10.2		First Amendment to the Amended and Restated Stockholders Agreement of C&J Energy Services, Inc. dated as of May 12, 2011 (incorporated herein by reference to Exhibit 10.16 to Amendment No. 2 to the C&J Energy Services, Inc’s Registration Statement on Form S-1/A, dated May 18, 2011 (Registration No. 333-173177))
10.3		Second Amendment to Amended and Restated Stockholders Agreement of C&J Energy Services, Inc. dated July 14, 2011 (incorporated herein by reference to Exhibit 10.19 to the C&J Energy Services, Inc’s Registration Statement on Form S-1, dated July 18, 2011 (Registration No. 333-173177))
* 31.1		Certification of Chief Executive Officer pursuant to Rule 13a-14(a) and 15d-14(a) as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
* 31.2		Certification of Chief Financial Officer pursuant to Rule 13a-14(a) and 15d-14(a) as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
** 32.1		Certification of Chief Executive Officer pursuant to 18 U.S.C. §1350 as adopted by Section 906 of the Sarbanes-Oxley Act of 2002.
** 32.2		Certification of Chief Financial Officer pursuant to 18 U.S.C. §1350 as adopted by Section 906 of the Sarbanes-Oxley Act of 2002
§101.INS		XBRL Instance Document
§101.SCH		XBRL Taxonomy Extension Schema Document

§101.CAL		XBRL Taxonomy Extension Calculation Linkbase Document
§101.LAB		XBRL Taxonomy Extension Label Linkbase Document
§101.PRE		XBRL Taxonomy Extension Presentation Linkbase Document
§101.DEF		XBRL Taxonomy Extension Definition Linkbase Document

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.

EXHIBIT INDEX

1.1		Underwriting Agreement, dated July 28, 2011, by and among C&J Energy Services, Inc., C&J Spec Rent Services, Inc., Total E&S, Inc., the Selling Stockholders named therein and Goldman, Sachs & Co. and J.P. Morgan Securities LLC (incorporated herein by reference to Exhibit 1.1 to the C&J Energy Services, Inc.’s Current Report on Form 8-K, filed on August 3, 2011 (File No. 001-35255))
3.1		Amended and Restated Certificate of Incorporation of C&J Energy Services, Inc. (incorporated herein by reference to Exhibit 3.1 to the C&J Energy Services, Inc’s Registration Statement on Form S-1, dated March 30, 2011 (Registration No. 333-173177))
3.2		Amended and Restated Bylaws of C&J Energy Services, Inc. (incorporated herein by reference to Exhibit 3.1 to the C&J Energy Services, Inc’s Registration Statement on Form S-1, dated March 30, 2011 (Registration No. 333-173177))
10.1		Credit Agreement, dated as of April 19, 2011, among C&J Energy Services, Inc. as Borrower, Bank of America, N.A. as Administrative Agent, Swing Line Lender and L/C Issuer, Comerica Bank as L/C Issuer and Syndication Agent, Wells Fargo Bank, National Association as Documentation Agent, and the Other Lenders party thereto (incorporated herein by reference to Exhibit 10.18 to Amendment No. 1 to the C&J Energy Services, Inc.’s Registration Statement on Form S-1/A, dated May 12, 2011 (Registration No. 333-173177))
10.2		First Amendment to the Amended and Restated Stockholders Agreement of C&J Energy Services, Inc. dated as of May 12, 2011 (incorporated herein by reference to Exhibit 10.16 to Amendment No. 2 to the C&J Energy Services, Inc’s Registration Statement on Form S-1/A, dated May 18, 2011 (Registration No. 333-173177))
10.3		Second Amendment to Amended and Restated Stockholders Agreement of C&J Energy Services, Inc. dated July 14, 2011 (incorporated herein by reference to Exhibit 10.19 to the C&J Energy Services, Inc’s Registration Statement on Form S-1, dated July 18, 2011 (Registration No. 333-173177))
* 31.1		Certification of Chief Executive Officer pursuant to Rule 13a-14(a) and 15d-14(a) as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
* 31.2		Certification of Chief Financial Officer pursuant to Rule 13a-14(a) and 15d-14(a) as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
** 32.1		Certification of Chief Executive Officer pursuant to 18 U.S.C. §1350 as adopted by Section 906 of the Sarbanes-Oxley Act of 2002.
** 32.2		Certification of Chief Financial Officer pursuant to 18 U.S.C. §1350 as adopted by Section 906 of the Sarbanes-Oxley Act of 2002
§101.INS		XBRL Instance Document
§101.SCH		XBRL Taxonomy Extension Schema Document
§101.CAL		XBRL Taxonomy Extension Calculation Linkbase Document
§101.LAB		XBRL Taxonomy Extension Label Linkbase Document
§101.PRE		XBRL Taxonomy Extension Presentation Linkbase Document
§101.DEF		XBRL Taxonomy Extension Definition Linkbase Document