C&J Energy Services 10-Q 2012 Q1 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended March 31, 2012.

or

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

For the transition period from             to             

Commission File Number: 001-35255

C&J Energy Services, Inc.

(Exact name of registrant as specified in its charter)

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

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

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	¨	Accelerated filer	¨
Non-accelerated filer	x  (Do not check if a smaller reporting company)	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  ¨     No  x

The number of shares of the registrant’s common stock, par value $0.01 per share, outstanding at May 4, 2012, was 51,952,743.

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

TABLE OF CONTENTS

		Page
PART I – FINANCIAL INFORMATION
Item 1.	Financial Statements
	Consolidated Balance Sheets as of March 31, 2012 and December 31, 2011		1
	Consolidated Statements of Operations for the three months ended March 31, 2012 and 2011		2
	Consolidated Statements of Changes in Stockholders’ Equity for the year ended December  31, 2011 and the three months ended March 31, 2012		3
	Consolidated Statements of Cash Flows for the three months ended March 31, 2012 and 2011		4
	Notes to Consolidated Financial Statements		5
	Cautionary Note Regarding Forward-Looking Statements		12
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		14
Item 3.	Quantitative and Qualitative Disclosure About Market Risk		22
Item 4.	Controls and Procedures		22
PART II – OTHER INFORMATION
Item 1.	Legal Proceedings		23
Item 1A.	Risk Factors		23
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		23
Item 3.	Defaults Upon Senior Securities		23
Item 4.	Mine Safety Disclosures		23
Item 5.	Other Information		23
Item 6.	Exhibits		24
	Signatures		25

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C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Amounts in thousands, except share data)

	March 31, 2012		December 31, 2011
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	78,200	$	46,780
Accounts receivable, net of allowance of $965 at March 31, 2012 and $808 at December 31, 2011		125,136		122,169
Inventories, net		63,190		45,440
Prepaid and other current assets		5,649		9,138
Deferred tax assets		827		789
Total current assets		273,002		224,316
Property, plant and equipment, net of accumulated depreciation of $52,304 at March 31, 2012 and $46,539 at December 31, 2011		246,876		213,697
Other assets:
Goodwill		65,057		65,057
Intangible assets, net of accumulated amortization of $9,387 at March 31, 2012 and $8,151 at December 31, 2011		24,183		25,419
Deposits on equipment under construction		4,683		6,235
Deferred financing costs, net of accumulated amortization of $558 at March 31, 2012 and $411 at December 31, 2011		2,381		2,528
Other noncurrent assets, net		597		597
Total assets	$	616,779	$	537,849
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	59,011	$	57,564
Payroll and related costs		5,578		4,799
Accrued expenses		4,179		9,626
Income taxes payable		24,334		1,823
Customer advances and deposits		8,530		5,392
Other current liabilities		33		33
Total current liabilities		101,665		79,237
Deferred tax liabilities		65,526		62,471
Other long-term liabilities		1,062		1,086
Total liabilities		168,253		142,794
Commitments and contingencies
Stockholders’ equity
Common stock, par value of $0.01, 100,000,000 shares authorized, 51,952,743 issued and outstanding at March 31, 2012 and 51,886,574 issued and outstanding at December 31, 2011		520		519
Additional paid-in capital		205,965		201,874
Retained earnings		242,041		192,662
Total stockholders’ equity		448,526		395,055
Total liabilities and stockholders’ equity	$	616,779	$	537,849

See accompanying notes to consolidated financial statements

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C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTSOF OPERATIONS

(Amounts in thousands, except per share data)

(Unaudited)

	Three Months Ended March 31,
	2012			2011
Revenue	$	239,052		$	127,204
Cost of sales		144,363			70,048
Gross profit		94,689			57,156
Selling, general and administrative expenses		18,330			8,825
(Gain) loss on sale/disposal of assets		397			(90	)
Operating income		75,962			48,421
Other expense:
Interest expense, net		(380	)		(1,958	)
Other expense, net		(72	)		(12	)
Total other expense, net		(452	)		(1,970	)
Income before income taxes		75,510			46,451
Income tax expense		26,131			17,366
Net income	$	49,379		$	29,085
Net income per common share (see Note 1):
Basic	$	0.95		$	0.61
Diluted	$	0.92		$	0.60
Weighted average common shares outstanding:
Basic		51,905			47,499
Diluted		53,715			48,697

See accompanying notes to consolidated financial statements

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C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTSOF CHANGESIN STOCKHOLDERS’ EQUITY

(Amounts in thousands)

	Common Stock				Additional Paid-in Capital		Retained Earnings
	Number of Shares		Amount, at $0.01 par value						Total
Balance, December 31, 2010		47,499	$	475	$	78,288	$	30,683	$	109,446
Issuance of common stock		4,300		43		112,104		—		112,147
Exercise of stock options		88		1		124		—		125
Excess tax benefit from stock-based award activity		—		—		512		—		512
Stock-based compensation		—		—		10,846		—		10,846
Net income		—		—		—		161,979		161,979
Balance, December 31, 2011		51,887		519		201,874		192,662		395,055
Exercise of stock options		66		1		201		—		202
Excess tax benefit from stock-based award activity		—		—		374		—		374
Stock-based compensation		—		—		3,516		—		3,516
Net income		—		—		—		49,379		49,379
Balance, March 31, 2012*		51,953	$	520	$	205,965	$	242,041	$	448,526

* Unaudited

See accompanying notes to consolidated financial statements

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C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTSOF CASH FLOWS

(Amounts in thousands)

(Unaudited)

	Three Months Ended March 31,
	2012			2011
Cash flows from operating activities:
Net income	$	49,379		$	29,085
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		7,845			3,603
Deferred income taxes		3,017			13,835
Provision for doubtful accounts, net of write-offs		150			68
(Gain) loss on sale/disposal of assets		397			(90	)
Stock-based compensation expense		3,516			2,132
Excess tax benefit from stock-based award activity		(374	)		—
Amortization of deferred financing costs		147			291
Changes in operating assets and liabilities:
Accounts receivable		(3,117	)		(27,483	)
Inventories		(17,750	)		(6,277	)
Prepaid expenses and other current assets		3,489			(2,599	)
Accounts payable		1,447			13,567
Accrued liabilities		(4,668	)		(2,009	)
Accrued taxes		22,885			(492	)
Deferred income		—			(4,000	)
Other		3,123			85
Net cash provided by operating activities		69,486			19,716
Cash flows from investing activities:
Purchases of and deposits on property and equipment		(38,759	)		(29,784	)
Proceeds from disposal of property and equipment		117			2,342
Net cash used in investing activities		(38,642	)		(27,442	)
Cash flows from financing activities:
Payments on revolving debt, net		—			(1,000	)
Proceeds from long-term debt		—			12,750
Repayments of long-term debt		—			(4,722	)
Financing costs		—			(63	)
Proceeds from stock options exercised		202			—
Excess tax benefit from stock-based award activity		374			—
Net cash provided by financing activities		576			6,965
Net increase (decrease) in cash and cash equivalents		31,420			(761	)
Cash and cash equivalents, beginning of period		46,780			2,817
Cash and cash equivalents, end of period	$	78,200		$	2,056
Supplemental cash flow disclosure:
Cash paid for interest	$	253		$	1,639
Cash paid for taxes	$	229		$	4,037

See accompanying notes to consolidated financial statements

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C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTESTO 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, Western Oklahoma and West Texas/East New Mexico. Through Total, the Company also manufactures and repairs equipment for companies in the energy services industry as well as equipment to fulfill the Company’s internal equipment demands.

Basis of Presentation and Principles of Consolidation

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, 2011 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, 2011, which are included in the Company’s Annual Report on Form 10-K filed with the SEC on February 29, 2012. 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.

These consolidated financial statements include the accounts of C&J and its 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 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 intangible assets, useful lives used in depreciation and amortization, income taxes and stock-based compensation. 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.

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C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTESTO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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 5 – Segment Information for further discussion regarding the Company’s reportable segments.

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

	March 31, 2012			December 31, 2011
Manufacturing parts	$	10,365		$	6,809
Work-in-process		9,838			7,133
Finished goods		43,434			31,844
		63,637			45,786
Inventory reserve		(447	)		(346	)
	$	63,190		$	45,440

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 may also include 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

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C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTESTO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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 generally does not sell or otherwise charge a fee separate and apart from the services it provides for any 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, conduct equipment repair services and provide oilfield parts and supplies 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 the 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 3 – Stock-Based Compensation.

Fair Value of Financial Instruments

The Company’s financial instruments consist of cash and cash equivalents, accounts receivable, accounts 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 value of long-term debt approximates its fair value, as interest approximates market rates.

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 deferred tax assets and liabilities are individually classified as current and noncurrent 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.

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C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTESTO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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).

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

	Three Months Ended March 31,
	2012		2011
	(In thousands, except per share amounts)
Numerator:
Net income attributed to common shareholders	$	49,379	$	29,085
Denominator:
Weighted average common shares outstanding		51,905		47,499
Effect of potentially dilutive common shares:
Stock options		1,810		1,198
Weighted average common shares outstanding and assumed conversions		53,715		48,697
Income per common share:
Basic	$	0.95	$	0.61
Diluted	$	0.92	$	0.60
Potentially dilutive securities excluded as anti-dilutive		1,184		3,648

Reclassifications

Certain reclassifications have been made to the prior years’ consolidated financial statements to conform to the current year presentations, which had no effect on the financial position, results of operations or cash flows of the Company.

Note 2 - Long-Term Debt

Senior Secured Revolving Credit Facility

On April 19, 2011, the Company entered into a 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 line of credit issuer, Comerica Bank, as line of credit issuer and syndication agent, Wells Fargo Bank, National Association, as documentation agent, and various other lenders. Obligations under the Credit Facility are guaranteed by the Subsidiaries. As of March 31, 2012 and December 31, 2011, no amounts were outstanding under the Credit Facility leaving the entire $200.0 million available for borrowing.

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C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTESTO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Loans under the 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 the Company’s election, plus an applicable margin that ranges from 1.25% to 2.00% for base rate loans and from 2.25% to 3.00% for LIBOR loans, based upon the Company’s leverage ratio, which is the ratio of funded indebtedness to EBITDA (as defined in the Credit Facility) for the Company and its Subsidiaries on a consolidated basis. 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.

The Credit Facility contains customary affirmative covenants including financial reporting, governance and notification requirements. The Credit Facility requires the Company 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 under the Credit Facility as of March 31, 2012.

Note 3 - Stock-Based Compensation

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 makes estimates with respect to 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. For options granted prior to the Company’s initial public offering, which closed on August 3, 2011, the calculation of the Company’s stock price involved the use of different valuation techniques, including a combination of an income and/or market approach. Determination of the fair value was a matter of judgment and often involved the use of significant estimates and assumptions. The following table presents the assumptions used in determining the fair value of option awards of 53,000 and 484,335 for the three months ended March 31, 2012 and 2011, respectively.

	Three Months Ended March 31,
	2012	2011
Expected volatility	75.0%	75.0%
Expected dividends	None	None
Exercise price	$16.88-$18.76	$10.00-$11.00
Expected term (in years)	5 - 6	5 - 6
Risk-free rate	1.0%-1.4%	2.2%-2.6%

As of March 31, 2012, the Company had 6,767,921 options outstanding to employees and nonemployee directors. As of March 31, 2012 there were 667,618 shares available for issuance under the 2010 Plan.

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C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTESTO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 4 - Commitments and Contingencies

Hydraulic Fracturing Term Contracts

The Company has entered into certain multi-year take-or-pay contracts that guarantee a minimum level of monthly revenue because 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. 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.

Litigation

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 on the Company’s consolidated financial position, results of operation or liquidity.

Note 5 - Segment Information

In accordance with FASB Accounting Standards Codification (“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. 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, two operating and reportable segments exist: 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, conducts equipment repair services and provides 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 table sets 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 2011 period has not been presented because, as previously mentioned, the Company did not have separate operating segments prior to the acquisition of Total.

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C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTESTO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

	Stimulation and Well Intervention Services		Equipment Manufacturing		Corporate and Other			Total
	(in thousands)
Three months ended March 31, 2012
Revenue from external customers	$	226,545	$	12,507	$	—		$	239,052
Inter-segment revenues		—		15,841		(15,841	)		—
Adjusted EBITDA		91,635		3,690		(11,193	)		84,132
Depreciation and amortization		6,688		1,042		115			7,845
Operating income (loss)		84,947		2,649		(11,634	)		75,962
Capital expenditures		42,611		748		(4,600	)		38,759
As of March 31, 2012
Identifiable assets	$	562,027	$	63,625	$	(8,873	)	$	616,779

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, a non-GAAP financial measure, 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 Exchange Act of 1934, as amended (the “Exchange Act”), 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).

	Three Months Ended March 31, 2012
Adjusted EBITDA	$	84,132
Interest expense, net		(380	)
Provision for income taxes		(26,131	)
Depreciation and amortization		(7,845	)
Gain (loss) on disposal of assets		(397	)
Net income	$	49,379

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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This Quarterly Report on Form 10-Q (this “Form 10-Q”) includes certain statements and information that may constitute “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 Exchange Act. The words “anticipate,” “believe,” “ensure,” “expect,” “if,” “intend,” “plan,” “estimate,” “project,” “forecasts,” “predict,” “outlook,” “aim,” “will,” “could,” “should,” “potential,” “would,” “may,” “probable,” “likely,” and similar expressions that convey the uncertainty of future events or outcomes, and the negative thereof, are intended to identify forward-looking statements. Forward-looking statements, which are not generally historical in nature, include those that express a belief, expectation or intention regarding our future activities, 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.

Forward-looking statements are not assurances of future performance and actual results could differ materially from our historical experience and our present expectations or projections. These forward-looking statements are based on management’s current expectations and beliefs, forecasts for our existing operations, experience, expectations and perception of historical trends, current conditions, anticipated future developments and their effect on us, and other factors believed to be appropriate. Although management believes the expectations and assumptions reflected in these forward-looking statements are reasonable as and when made, no assurance can be given that these assumptions are accurate or that any of these expectations will be achieved (in full or at all). Our forward-looking statements involve significant risks, contingencies and uncertainties, most of which are difficult to predict and many of which are beyond our control. Known material factors that could cause actual results to differ materially from those in the forward-looking statements 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;

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• 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.

For additional information regarding known material factors that could affect our operating results and performance, please read (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 and (2) our Annual Report on Form 10-K for the fiscal year ended December 31, 2011. Should one or more of these known material risks occur, or should the underlying assumptions prove incorrect, our actual results, performance, achievements or plans could differ materially from those expressed or implied in any forward-looking statement.

Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. We undertake no obligation to publicly update or revise any forward-looking statements after the date they are made, whether as a result of new information, future events or otherwise.

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ITEM 2. MANAGEMENT’S DISCUSSIONAND ANALYSISOF FINANCIAL CONDITIONAND RESULTSOF 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 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, 2011 included in our Annual Report on Form 10-K filed with the SEC on February 29, 2012.

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 section titled “Cautionary Note Regarding Forward-Looking Statements” of this Form 10-Q.

Overview

We are an independent provider of premium hydraulic fracturing, coiled tubing and pressure pumping services with a focus on complex, technically-demanding well completions. These services, which are offered through our Stimulation and Well Intervention Services segment, are provided in conjunction with both unconventional and conventional well completions as well as stimulation and workover operations for existing wells. In addition, our Equipment Manufacturing segment, which is conducted through Total, manufactures and repairs equipment for our internal needs as well as for third-party companies in the energy services industry.

We provide our Stimulation and Well Intervention Services in what we believe to be some of the most geologically challenging basins in South Texas, East Texas/North Louisiana, Western Oklahoma and West Texas/East New Mexico. We currently operate seven modern, 15,000 pounds per square inch, pressure rated hydraulic fracturing fleets with an aggregate 242,000 horsepower, and we currently have on order two additional hydraulic fracturing fleets, which we expect to be delivered and deployed in the third quarter and fourth quarter of 2012, respectively. The acquisition of these two additional fleets will increase our total capacity to more than 300,000 horsepower by the end of 2012. We also operate a fleet of 18 coiled tubing units and we have six new coiled tubing units on order, which we expect to be delivered and deployed by the end of 2012. Additionally, we have 20 double pumps, three single pumps and five high pressure pump down units in our standalone pressure pumping line. In anticipation of the delivery and deployment of this new equipment in 2012, we 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.

With the acquisition of Total on April 28, 2011, we commenced our Equipment Manufacturing business. In addition to manufacturing hydraulic fracturing, coiled tubing, pressure pumping and other equipment used in the energy services industry, through Total we also provide equipment repair services and sell oilfield parts and supplies to third-party customers in the energy services industry, and to meet our own internal needs. Following our acquisition of Total, we acquired approximately ten acres of property adjacent to Total’s current facility and constructed an approximate 36,000 square foot manufacturing facility, which was completed in December 2011. By significantly increasing Total’s manufacturing capacity, we expect to further increase its ability to service our Stimulation and Well Intervention Services segment and existing and future third-party customers, and to enhance our research and development efforts around equipment and innovation.

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Our Business

Stimulation and Well Intervention Services Segment

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

Hydraulic Fracturing. Approximately 78% of our consolidated revenues for the three months ended March 31, 2012 were derived from hydraulic fracturing services. Six of our hydraulic fracturing fleets are currently working under term contracts: Fleet 1 has been extended, in accordance with provisions in the current contract, for 12 months through mid-2013 to a producer operating in the Eagle Ford shale; Fleet 2 has been extended, in accordance with provisions in the current contract, for three months through late 2012 to a producer operating in the Eagle Ford shale, with the possibility for a longer-term extension; Fleet 3 is dedicated through early 2013 to a producer operating in the Eagle Ford shale; Fleet 4 is dedicated through mid-2014 to a producer operating in the Haynesville shale; Fleet 5 is dedicated through mid-2013 to a producer operating in the Eagle Ford shale; and Fleets 6A and 6B are dedicated through early 2014 to a producer operating in the Permian Basin. Fleet 4 remains under contract but has been redeployed to the Eagle Ford shale for committed work, with spot market availability for new customers working in the Eagle Ford shale, as well as the Permian Basin. The customer relationship remains in place and this fleet may be redeployed to the Haynesville shale at the election of the contract customer with timely notice.

We took full delivery of all pumps and initially ordered ancillary equipment for our seventh hydraulic fracturing fleet in April 2012. The 32,000 horsepower fleet was deployed in late-April for spot market work in the Eagle Ford shale in South Texas and the Permian Basin in West Texas. We are scheduled to take delivery of Fleets 8 and 9 in the third quarter of 2012 and the fourth quarter of 2012, respectively. We are seeking to secure multi-year take-or-pay contracts for Fleets 7, 8, and 9, although, we believe that the equipment can generate attractive returns in the spot market if long-term contracts are not secured.

Our term contracts generally range from one year to three years. Under the term contacts, typically 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 use more than the specified contract minimums, we will be paid a pre-agreed amount for the provision of such additional services. Our term contracts typically 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.

In addition to operating our recently deployed seventh hydraulic fracturing fleet in the spot market, some of 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, which is typically higher than the rates under our term contracts. We may also charge fees for setup 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. This spot market activity not only has a positive impact on revenue and earnings, but also acts as a marketing tool, enabling us to introduce our services to new customers and strengthen our relationships with the existing customers.

Our hydraulic fracturing business contributed $186.4 million of revenue and completed 1,476 fracturing stages during the first quarter of 2012, compared to $172.6 million of revenue and 1,151 fracturing stages during the fourth quarter of 2011. During the three months ended March 31, 2012, we averaged monthly revenue per unit of horsepower of $319 compared to $343 for the previous quarter. Hydraulic fracturing revenue for the first quarter of 2011 was $104.9 million and 633 fracturing stages were completed. Average monthly revenue per unit of horsepower was $383 for the first quarter of 2011.

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Coiled Tubing and Pressure Pumping. Approximately 17% of our consolidated revenues for the three months ended March 31, 2012 were derived from coiled tubing and pressure pumping services. Our coiled tubing, pressure pumping and other related well intervention services are generally provided in the spot market at prevailing prices per hour, although we do have three contracts in place with major operators for dedicated coiled tubing and associated services. We may also charge fees for setup and mobilization of equipment depending on the job. The setup 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.

Our coiled tubing business contributed $35.5 million of revenue and we completed 908 coiled tubing jobs during the first quarter of 2012, compared to $32.0 million of revenue and 849 coiled tubing jobs during the previous quarter. Coiled tubing revenue for the first quarter of 2011 was $17.4 million and 638 jobs were completed. We currently have a fleet of 18 coiled tubing units with six new coiled tubing units on order that are expected to be deployed before the end of 2012 in new geographic basins. Our pressure pumping business generated $4.6 million of revenue during the first quarter of 2012, compared to $4.3 million during the fourth quarter of 2011 and $4.9 million for the prior year quarter.

Equipment Manufacturing Segment

Approximately 5% of our consolidated revenues for the three months ended March 31, 2012 were derived from our Equipment Manufacturing segment. Our Equipment Manufacturing segment constructs oilfield equipment, including hydraulic fracturing pumps, coiled tubing units, pressure pumping units and other equipment, for our Stimulation and Well Intervention Services segment as well as for third-party customers in the energy services industry. This segment also provides equipment repair services and oilfield parts and supplies to the energy services industry and to meet the needs of our Stimulation and Well Intervention Services segment.

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 industry in which we operate. 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 section titled “Cautionary Note Regarding Forward-Looking Statements” of this Form 10-Q and the section titled “Risk Factors” in this Form 10-Q and in our Annual Report on Form 10-K for additional information about the risks we face.

Equipment Supply. The overall number of 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 our business. We expect to take delivery of and deploy two new hydraulic fracturing fleets, Fleets 8 and 9, in the third quarter of 2012 and in the fourth quarter of 2012, respectively. In addition, we have ordered six new coiled tubing units along with related ancillary equipment, each of which we expect to take delivery of in 2012. 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 acquisition of Total, a significant supplier of our hydraulic fracturing and coiled tubing equipment, has provided us with added monitoring capabilities and control over access to, and delivery of, new fracturing equipment.

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Hydraulic Fracturing Legislation and Regulation. Congress has from time to time, including during the current session, considered legislation to provide for federal regulation of hydraulic fracturing and to require public disclosure of the chemicals used in the fracturing process. If such current or any future federal legislation becomes law, it 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 our five-year $200.0 million Credit Facility and had no amounts outstanding as of May 4, 2012, leaving the entire $200.0 million available for borrowing. In addition, our cash flows from operations have continued to increase, with cash flows from operations during the three months ended March 31, 2012 increasing by $49.8 million from the same period in 2011 and we ended the quarter with $78.2 million cash on hand as of March 31, 2012. We believe that the combination of our cash on hand, which was $74.4 million as of May 4, 2012, 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 2012.

Outlook

Demand for our 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 equipment 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:

• ongoing development of existing and emerging unconventional resource basins;

• increased horizontal drilling and greater service intensity in unconventional resource basins, particularly in oily- and liquids-rich formations where we are seeing enhanced economics, through the application of completion technologies such as hydraulic fracturing;

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• improved drilling efficiencies increasing the number of horizontal feet per day requiring completion services; and

• increased hydraulic fracturing intensity, particularly with increasingly longer laterals and a greater number of fracturing stages per well, in more demanding and technically complex formations.

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, our profitability is generally 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 six out of our seven existing fleets. We are seeking to secure multi-year take-or-pay contracts for Fleets 7, 8, and 9, although we believe that the equipment can generate attractive returns in the spot market if long-term contracts are not secured.

Our revenues and results of operations were positively impacted by: (1) the addition and deployment of Fleet 4 in April 2011; (2) the addition and deployment of Fleet 5 in August 2011; (3) the addition and deployment of Fleet 6A in December 2011 and Fleet 6B in February 2012; (4) the addition and deployment of five new coiled tubing units during 2011; and (5) the acquisition of Total in April 2011. In the near term, we also expect our revenues and results of operations to be positively impacted by the deployment of Fleets 7, 8 and 9 in April 2012, the third quarter of 2012 and the fourth quarter of 2012, respectively. We expect that our results of operations in 2012 compared to 2011 will be significantly impacted by the dramatic growth of our asset base over the last twelve months.

Results for the Three Months Ended March 31, 2012 Compared to the Three Months Ended March 31, 2011

The following table summarizes the change in our results of operations for the three months ended March 31, 2012 when compared to the three months ended March 31, 2011 (in thousands):

	Three Months Ended March 31,
	2012			2011			$ Change
Revenue	$	239,052		$	127,204		$	111,848
Cost of Sales		144,363			70,048			74,315
Gross profit		94,689			57,156			37,533
Selling, general and administrative expenses		18,330			8,825			9,505
Loss on disposal of assets		397			(90	)		487
Operating income		75,962			48,421			27,541
Other income (expense):
Interest expense, net		(380	)		(1,958	)		1,578
Other income (expense), net		(72	)		(12	)		(60	)
Total other expenses, net		(452	)		(1,970	)		1,518
Income before income taxes		75,510			46,451			29,059
Provision for income taxes		26,131			17,366			8,765
Net income	$	49,379		$	29,085		$	20,294

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Revenue

Revenue increased $111.8 million, or 88%, to $239.1 million for the three months ended March 31, 2012, as compared to $127.2 million for the same period in 2011. This increase was primarily due to the deployment of additional hydraulic fracturing equipment in our Stimulation and Well Intervention Services segment. Fleets 4, 5, 6A and 6B, which were deployed in April 2011, August 2011, December 2011 and February 2012, respectively, contributed $93.2 million of incremental revenue in the first quarter of 2012. The additional increase in revenue was due to the addition of five coiled tubing units and the acquisition of Total in April 2011.

Cost of Sales

Cost of sales increased $74.3 million, or 106%, to $144.4 million for the three months ended March 31, 2012, compared to $70.0 million for the same period in 2011 primarily due to the significant quarter-over-quarter increase in revenue and to a lesser extent, increased costs associated with our Equipment Manufacturing business segment which we entered into with the acquisition of Total in the second quarter of 2011.

Selling, General and Administrative Expenses (“SG&A”)

SG&A increased $9.5 million, or 108%, to $18.3 million for the three months ended March 31, 2012, as compared to $8.8 million for the same period in 2011. 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, $1.9 million in higher long-term and short-term incentive costs, $0.7 million in higher professional fees and $0.4 million in higher property taxes. We also incurred $2.2 million in increased SG&A costs related to Total, which was acquired in April 2011.

Interest Expense

Interest expense decreased by $1.6 million, or 81%, to $0.4 million for the three months ended March 31, 2012 as compared to $2.0 million for the same period in 2011. The decrease was primarily attributable to lower average outstanding debt balances and, to a lesser extent, lower interest rates.

Income Taxes

We recorded a tax provision of $26.1 million for the three months ended March 31, 2012, at an effective rate of 34.6%, compared to a tax provision of $17.4 million for the three months ended March 31, 2011, at an effective rate of 37.4%. The decrease in our effective rate quarter over quarter is primarily attributable to certain qualifying deductions reflected in income tax provision for the first quarter of 2012 provision that were not included in the provision for the first quarter of 2011.

Liquidity and Capital Resources

Our primary sources of liquidity to date have been capital contributions from stockholders, the net proceeds that we received from our IPO, 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 2011 and we anticipate capital expenditures will continue to increase through 2012. We have ordered two new hydraulic fracturing fleets, Fleets 8 and 9, which are scheduled for delivery in the third quarter of 2012 and the fourth quarter of 2012, respectively. Fleet 8 has an aggregate cost of approximately $29 million, of which approximately $10.0 million had been funded as of May 4, 2012; and Fleet 9 has an aggregate cost of approximately $30 million, of which approximately $2.2 million had been funded as of May 4, 2012. In addition, we have ordered six new coiled tubing units along with related ancillary equipment for delivery in 2012 with a combined aggregate cost of

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approximately $20 million, of which approximately $0.9 million had been funded as of May 4, 2012. We intend to fund the remaining costs of the two hydraulic fracturing fleets and six coiled tubing units through a combination of cash on hand, which was $74.4 million as of May 4, 2012, cash flows from operations, and, to the extent necessary, borrowings under our credit facility.

On April 19, 2011, we entered into a five-year $200.0 million revolving 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 May 4, 2012.

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 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 at least 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. 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 our common stock 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. For more information concerning the Credit Facility, please read “Description of Our Indebtedness” elsewhere in this Form 10-Q.

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. We expect our total 2012 capital expenditures to be approximately $145 to $160 million, of which $46.8 million has been incurred as of May 4, 2012. The remainder of our estimated capital expenditures for 2012 includes the purchase of Fleets 8 and 9, six new coil tubing units and maintenance capital expenditures.

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Historically, we have primarily grown through organic expansion and with the acquisition of Total we enhanced our manufacturing and repair capabilities through vertical integration. We will continue to evaluate opportunities to expand our business through selective acquisitions and make capital investment decisions that we believe will support our long-term growth strategy. 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):

	Three Months Ended March 31,
	2012			2011
Cash flow provided by (used in):
Operating activities	$	69,486		$	19,716
Investing activities		(38,642	)		(27,442	)
Financing activities		576			6,965
Change in cash and cash equivalents	$	31,420		$	(761	)

Cash Provided by Operating Activities

Net cash provided by operating activities increased $49.8 million for the three months ended March 31, 2012 as compared to the same period in 2011. This increase was primarily due to higher net income and accounts receivable. The increase in net income and accounts receivable is attributable to the growth in our revenue year over year in connection with the deployment of additional hydraulic fracturing fleets and coiled tubing units as well as the acquisition of Total.

Cash Flows Used in Investing Activities

Net cash used in investing activities increased $11.2 million for the three months ended March 31, 2012 as compared to the same period in 2011. This increase was due primarily to higher capital expenditures related to the expansion of our hydraulic fracturing services business. For the three months ended March 31, 2012 we spent $31.5 million primarily related to our sixth, seventh, eighth and ninth fleets.

Cash Flows Provided by Financing Activities

Net cash provided by financing activities decreased $6.4 million for the three months ended March 31, 2012 as compared to the same period in 2011. The decrease was primarily due to borrowings from our Credit Facility during 2011.

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 March 31, 2012.

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Description of Our Indebtedness

Senior Secured Credit Agreement. On April 19, 2011, we entered into a 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 other lenders. Our obligations under our Credit Facility are guaranteed by our Subsidiaries, Spec-Rent and Total. As of May 4, 2012, there were no 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 ranges from 1.25% to 2.00% for base rate loans and from 2.25% to 3.00% for LIBOR loans, 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. 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.

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.

ITEM 3. QUANTITATIVEAND 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” or “Quantitative and Qualitative Disclosures About Market Risk” in our Annual Report on Form 10-K.

ITEM 4. CONTROLSAND 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 March 31, 2012.

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 March 31, 2012 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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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 other information set forth in this Form 10-Q, including under the section titled “Cautionary Note Regarding Forward-Looking Statements,” you should carefully consider the information set forth in the section entitled “Risk Factors” of our Annual Report on Form 10-K for the year ended December 31, 2011, for a detailed discussion of known material factors which could materially affect our business, financial condition or future results. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition or future results.

Recently approved final rules regulating air emissions from natural gas production operations could cause our customers and us to incur increased capital expenditures and operating costs as well as reduce the demand for our services.

On April 17, 2012, the EPA approved final regulations under the Clean Air Act that, among other things, require additional emissions controls for natural gas and natural gas liquids production, including New Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds (“VOCs”) and a separate set of emission standards to address hazardous air pollutants frequently associated with such production activities. The final regulations require, among other things, the reduction of VOC emissions from natural gas wells through the use of reduced emission completions or “green completions” on all hydraulically fractured wells constructed or refractured after January 1, 2015. For well completion operations occurring at such well sites before January 1, 2015, the final regulations allow operators to capture and direct flowback emissions to completion combustion devices, such as flares, in lieu of performing green completions. These regulations could require a number of modifications to our customer’s as well as our operations including the installation of new equipment, which could result in significant costs, including increased capital expenditures and operating costs. The incurrence of such expenditures and costs by our exploration and production customers’ could result in reduced production by those customers and thus translate into reduced demand for our services.

ITEM 2. UNREGISTERED SALESOF EQUITY SECURITIESAND USEOF PROCEEDS

None.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4. MINE SAFETY DISCLOSURES

None.

ITEM 5. OTHER INFORMATION

None.

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ITEM 6. EXHIBITS

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

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	Second Amended and Restated Bylaws of C&J Energy Services, Inc., effective February 27, 2012 (incorporated herein by reference to Exhibit 3.1 to the C&J Energy Services, Inc.’s Current Report on Form 8-K, filed on February 29, 2012 (File No. 001-35255))
*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

* Filed herewith

** Furnished herewith in accordance with Item 601(b)(32) of Regulation S-K.

*** In accordance with Rule 406T of Regulation S-T, the information in these exhibits shall not be deemed to be “filed” for purposes of Section 18 of the Exchange Act, or otherwise subject to liability under that section, and shall not be deemed to be incorporated by reference into any filing under the Securities Act or the Exchange Act, except as expressly set forth by specific reference in such filing.

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SIGNATURES

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

	C&J ENERGY SERVICES, INC.
Date: May 9, 2012	By:	/s/    RANDALL C. MCMULLEN, JR.
		Randall C. McMullen, Jr.
		Executive Vice President, Chief Financial Officer and Treasurer (Duly Authorized Officer and Principal Financial Officer)

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EXHIBIT INDEX

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	Second Amended and Restated Bylaws of C&J Energy Services, Inc., effective February 27, 2012 (incorporated herein by reference to Exhibit 3.1 to the C&J Energy Services, Inc.’s Current Report on Form 8-K, filed on February 29, 2012 (File No. 001-35255))
*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

* Filed herewith

** Furnished herewith in accordance with Item 601(b)(32) of Regulation S-K.

*** In accordance with Rule 406T of Regulation S-T, the information in these exhibits shall not be deemed to be “filed” for purposes of Section 18 of the Exchange Act, or otherwise subject to liability under that section, and shall not be deemed to be incorporated by reference into any filing under the Securities Act or the Exchange Act, except as expressly set forth by specific reference in such filing.

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