C&J Energy Services 10-Q 2013 Q2 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 June 30, 2013

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 incorporation or organization)	(I.R.S. Employer Identification No.)

10375 Richmond Avenue, Suite 1910

Houston, Texas 77042

(Address of principal executive offices)

(713) 260-9900

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.     Yes  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	x	Accelerated filer	¨
Non-accelerated filer	¨  (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 August 2, 2013, was 54,472,756.

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

TABLE OF CONTENTS

	Page
PART I – FINANCIAL INFORMATION
Item 1. Financial Statements
Consolidated Balance Sheets as of June 30, 2013 and December 31, 2012		1
Consolidated Statements of Operations for the three and six months ended June 30, 2013 and 2012		2
Consolidated Statements of Changes in Stockholders’ Equity for the year ended December 31, 2012 and the six months ended June 30, 2013		3
Consolidated Statements of Cash Flows for the six months ended June 30, 2013 and 2012		4
Notes to Consolidated Financial Statements		5
Cautionary Note Regarding Forward-Looking Statements		15
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		17
Item 3. Quantitative and Qualitative Disclosures About Market Risk		28
Item 4. Controls and Procedures		28
PART II – OTHER INFORMATION
Item 1. Legal Proceedings		30
Item 1A. Risk Factors		30
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		31
Item 3. Defaults Upon Senior Securities		31
Item 4. Mine Safety Disclosures		31
Item 5. Other Information		31
Item 6. Exhibits		32
Signatures		33

-i-

PART I – FINANCIAL INFORMATION

ITEM 1. FINANCIALSTATEMENTS

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Amounts in thousands, except share data)

	June 30,		December 31,
	2013		2012
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	12,671	$	14,442
Accounts receivable, net of allowance of $1,368 at June 30, 2013 and $1,106 at December 31, 2012		175,173		167,481
Inventories, net		52,342		60,659
Prepaid and other current assets		11,166		3,984
Deferred tax assets		3,892		3,613
Total current assets		255,244		250,179
Property, plant and equipment, net of accumulated depreciation of $113,781 at June 30, 2013 and $84,848 at December 31, 2012		481,973		433,727
Other assets:
Goodwill		200,876		196,512
Intangible assets, net		125,197		123,487
Deposits on equipment under construction		1,413		1,033
Deferred financing costs, net of accumulated amortization of $1,914 at June 30, 2013 and $1,334 at December 31, 2012		3,268		3,848
Other noncurrent assets		4,027		3,971
Total assets	$	1,071,998	$	1,012,757
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	74,099	$	69,617
Payroll and related costs		16,269		10,896
Accrued expenses		15,696		17,286
Income taxes payable		13,247		4,029
Customer advances and deposits		534		1,092
Other current liabilities		2,156		2,122
Total current liabilities		122,001		105,042
Deferred tax liabilities		128,069		132,551
Long-term debt and capital lease obligations		157,651		173,705
Other long-term liabilities		1,665		1,568
Total liabilities		409,386		412,866
Commitments and contingencies
Stockholders’ equity
Common stock, par value of $0.01, 100,000,000 shares authorized, 54,386,370 issued and outstanding at June 30, 2013 and 53,131,823 issued and outstanding at December 31, 2012		544		531
Additional paid-in capital		241,065		224,348
Retained earnings		421,003		375,012
Total stockholders’ equity		662,612		599,891
Total liabilities and stockholders’ equity	$	1,071,998	$	1,012,757

See accompanying notes to consolidated financial statements

-1-

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTSOF OPERATIONS

(Amounts in thousands, except per share data)

(Unaudited)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2013			2012			2013			2012
Revenue	$	266,956		$	278,388		$	543,007		$	517,440
Costs and expenses:
Direct costs		180,370			168,322			367,455			308,896
Selling, general and administrative expenses		33,573			18,227			65,475			32,501
Depreciation and amortization		17,926			9,561			34,482			17,406
Loss on disposal of assets		232			212			322			609
Operating income		34,855			82,066			75,273			158,028
Other income (expense):
Interest expense, net		(1,673	)		(891	)		(3,333	)		(1,271	)
Other, net		54			—			120			(72	)
Total other income (expense)		(1,619	)		(891	)		(3,213	)		(1,343	)
Income before income taxes		33,236			81,175			72,060			156,685
Income tax expense		12,389			27,900			26,069			54,031
Net income	$	20,847		$	53,275		$	45,991		$	102,654
Net income per common share:
Basic	$	0.39		$	1.03		$	0.87		$	1.98
Diluted	$	0.38		$	0.99		$	0.84		$	1.91
Weighted average common shares outstanding:
Basic		52,797			51,957			52,665			51,931
Diluted		55,064			53,833			55,051			53,774

See accompanying notes to consolidated financial statements

-2-

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTSOF CHANGESIN STOCKHOLDERS’ EQUITY

(Amounts in thousands)

	Common Stock					Additional
	Number of			Amount, at		Paid-in			Retained
	Shares			$0.01 par value		Capital			Earnings		Total
Balance, December 31, 2011		51,887		$	519	$	201,874		$	192,662	$	395,055
Issuance of restricted stock		780			7		(7	)		—		—
Exercise of stock options		465			5		2,568			—		2,573
Tax effect of stock-based compensation		—			—		1,901			—		1,901
Stock-based compensation		—			—		18,012			—		18,012
Net income		—			—		—			182,350		182,350
Balance, December 31, 2012		53,132			531		224,348			375,012		599,891
Issuance of restricted stock, net of forfeitures		686			7		(7	)		—		—
Employee tax withholding on restricted stock vesting		(65	)		—		(1,181	)		—		(1,181	)
Exercise of stock options		633			6		4,115			—		4,121
Tax effect of stock-based compensation		—			—		2,222			—		2,222
Stock-based compensation		—			—		11,568			—		11,568
Net income		—			—		—			45,991		45,991
Balance, June 30, 2013*		54,386		$	544	$	241,065		$	421,003	$	662,612

* Unaudited

See accompanying notes to consolidated financial statements

-3-

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTSOF CASH FLOWS

(Amounts in thousands)

(Unaudited)

	Six Months Ended June 30,
	2013			2012
Cash flows from operating activities:
Net income	$	45,991		$	102,654
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		34,482			17,406
Deferred income taxes		(6,785	)		6,731
Provision for doubtful accounts, net of write-offs		334			300
Loss on disposal of assets		322			609
Stock-based compensation expense		11,568			7,086
Excess tax benefit from stock-based award activity		(2,240	)		(524	)
Amortization of deferred financing costs		580			342
Inventory write-down		870			—
Changes in operating assets and liabilities:
Accounts receivable		(7,900	)		(38,017	)
Inventories		7,448			(24,640	)
Prepaid expenses and other current assets		(7,178	)		194
Accounts payable		4,482			9,454
Accrued liabilities		2,535			(1,489	)
Accrued taxes		11,441			12,294
Other		(485	)		207
Net cash provided by operating activities		95,465			92,607
Cash flows from investing activities:
Purchases of and deposits on property, plant and equipment		(79,461	)		(77,865	)
Proceeds from disposal of property, plant and equipment		1,000			168
Payments made for business acquisitions, net of cash acquired		(7,934	)		(271,852	)
Net cash used in investing activities		(86,395	)		(349,549	)
Cash flows from financing activities:
Payments on revolving debt, net		(15,000	)		—
Proceeds from long-term debt		—			220,000
Repayments of capital lease obligations		(1,021	)		(128	)
Financing costs		—			(2,262	)
Proceeds from stock options exercised		4,121			306
Employee tax withholding on restricted stock vesting		(1,181	)		—
Excess tax benefit from stock-based award activity		2,240			524
Net cash (used in) provided by financing activities		(10,841	)		218,440
Net decrease in cash and cash equivalents		(1,771	)		(38,502	)
Cash and cash equivalents, beginning of period		14,442			46,780
Cash and cash equivalents, end of period	$	12,671		$	8,278
Supplemental cash flow disclosures:
Cash paid for interest	$	2,774		$	253
Cash paid for taxes	$	21,413		$	35,113
Non-cash consideration for business acquisition	$	900		$	—

See accompanying notes to consolidated financial statements

-4-

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., a Delaware corporation, was founded in Texas in 1997. Through its subsidiaries, the Company operates in three reportable segments: Stimulation and Well Intervention Services, Wireline Services and Equipment Manufacturing. The Company provides hydraulic fracturing, coiled tubing and other well stimulation services through its Stimulation and Well Intervention Services segment and cased-hole wireline and other complementary services through its Wireline Services segment to oil and natural gas exploration and production companies throughout the United States. In addition, the Company manufactures and repairs equipment and provides oilfield parts and supplies for third-party customers in the energy services industry through its Equipment Manufacturing segment, and also fulfills the Company’s internal equipment demands through this segment. See Note 6 – Segment Information for further discussion regarding the Company’s reportable segments. As used herein, references to the “Company” or “C&J” are to C&J Energy Services, Inc. together with its consolidated subsidiaries.

Basis of Presentation and Principles of Consolidation

The accompanying consolidated financial statements have not been audited by the Company’s independent registered public accounting firm, except that the consolidated balance sheet at December 31, 2012 is derived from audited consolidated financial statements. In the opinion of management, all adjustments, consisting of normal recurring adjustments, necessary for fair presentation have been included.

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, 2012, which are included in the Company’s Annual Report on Form 10-K, as amended. 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 revenue and expenses during the reporting period. Estimates are used in, 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 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.

Accounts Receivable and Allowance for Doubtful Account

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.

-5-

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTESTO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Inventories

Inventories for the Stimulation and Well Intervention Services segment and the Wireline Services segment consist of finished goods, including equipment components, chemicals, proppants, and general supplies and materials for the segments’ operations. Inventories for the Equipment Manufacturing segment consist of manufacturing parts and work-in-process. See Note 6 – 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. Inventories consisted of the following (in thousands):

	June 30,			December 31,
	2013			2012
Manufacturing parts	$	21,363		$	21,551
Work-in-process		2,374			1,523
Finished goods		29,221			38,164
Total inventory		52,958			61,238
Inventory reserve		(616	)		(579	)
Inventory, net of reserve	$	52,342		$	60,659

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 provides hydraulic fracturing services pursuant to term contracts and pricing agreements or on a spot market basis. Revenue is recognized and customers are invoiced upon the completion of each job, which can consist of one or more 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.

Under the Company’s term contracts, customers are typically obligated to pay 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 contracted minimums, the Company will be paid a pre-agreed amount for the provision of such additional services. As of June 30, 2013, the Company was providing hydraulic fracturing services under one term contract, which is scheduled to expire in early 2014.

The Company also performs hydraulic fracturing services pursuant to pricing agreements. Under such agreements, customers typically commit to targeted utilization levels at agreed pricing, but without termination penalties or obligations to pay for services not utilized by the customer. In addition, the agreed upon pricing is typically subject to periodic review, as specifically defined in the agreement, and may be adjusted to then-current market rates upon the agreement of both parties.

-6-

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTESTO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Rates for services performed on a spot market basis are based on an agreed-upon hourly spot market rate. The Company may also charge fees for setup and mobilization of equipment depending on the job, additional equipment used on the job, if any, and materials that are consumed during the fracturing process. 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.

Coiled Tubing. The Company enters into arrangements to provide coiled tubing and other well stimulation services. Jobs for these services are typically short term in nature, lasting anywhere from a few hours to multiple days. 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 for these services on an hourly basis 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. For services performed on a spot market basis, the necessary chemicals and proppants are typically provided by the Company and the customer is billed for those materials at cost plus an agreed upon markup. For services performed on a contractual basis, when the chemicals and proppants are provided by the Company, the customer is billed for those materials at a negotiated contractual rate. When chemicals and proppants are supplied by the customer, the Company typically charges handling fees based on the amount of chemicals and proppants used.

In addition, ancillary to coiled tubing and other well stimulation services revenue, the Company generates revenue from various fluids and supplies that are necessarily consumed during those processes.

Wireline Revenue. Wireline revenue is generated from the performance of cased-hole wireline and other complementary services, including logging, perforating, pipe recovery, pressure testing and pumpdown services. These jobs are typically short term in nature, lasting anywhere from a few hours to multiple days. Revenue is recognized when the services and equipment are provided and the job is completed. The Company typically charges the customer on a per job basis for these services at agreed-upon spot market rates.

Equipment Manufacturing Revenue. The Company enters into arrangements to construct equipment, conduct equipment repair services and provide oilfield parts and supplies to third-party customers in the energy services industry. Revenue is recognized and the customer is invoiced upon the completion and delivery of each order to the customer.

Stock-Based Compensation

The Company’s stock-based compensation plans provide the ability to grant equity awards to officers, employees, consultants and non-employee directors. As of June 30, 2013, only nonqualified stock options and restricted stock had been granted under such plans. The Company values option grants based on the grant date fair value by using the Black-Scholes option-pricing model and values restricted stock grants based on the closing price of C&J’s common stock on the date of grant. The Company recognizes stock-based compensation expense on a straight-line basis over the requisite service period. Further information regarding the Company’s stock-based compensation arrangements and the related accounting treatment can be found in Note 4 – Stock-Based Compensation.

-7-

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTESTO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Fair Value of Financial Instruments

The Company’s financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable, long-term debt and capital lease obligations. 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 and capital lease obligations approximate their fair value, as the interest rates approximate market rates.

Income Taxes

The Company accounts for income taxes utilizing the asset and liability method. Under this method, 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 as income or expense in the period that includes the enactment date.

The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. In assessing the likelihood and extent that deferred tax assets will be realized, consideration is given to projected future taxable income and tax planning strategies. A valuation allowance is recorded 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.

The Company recognizes the financial statement effects of a tax position when it is more-likely-than-not, based on the technical merits, that the position will be sustained upon examination. A tax position that meets the more-likely-than-not recognition threshold is measured as the largest amount of tax benefit that is greater than 50% likely of being realized upon ultimate settlement with a taxing authority. Previously recognized tax positions are reversed in the first period in which it is no longer more-likely-than-not that the tax position would be sustained upon examination. Income tax related interest and penalties, if applicable, are recorded as a component of the provision for income tax expense.

Earnings Per Share

Basic earnings per share is based on the weighted average number of shares of common stock (“common shares”) outstanding during the applicable period and excludes shares subject to outstanding stock options and shares of restricted stock. Diluted earnings per share is computed based on the weighted average number of common shares outstanding during the period plus, when their effect is dilutive, incremental shares consisting of shares subject to outstanding stock options and restricted stock.

-8-

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTESTO 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,
	2013		2012		2013		2012
	(In thousands, except per share amounts)
Numerator:
Net income attributed to common shareholders	$	20,847	$	53,275	$	45,991	$	102,654
Denominator:
Weighted average common shares outstanding		52,797		51,957		52,665		51,931
Effect of potentially dilutive common shares:
Stock options		2,047		1,876		2,145		1,843
Restricted stock		220		—		241		—
Weighted average common shares outstanding and assumed conversions		55,064		53,833		55,051		53,774
Earnings per common share:
Basic	$	0.39	$	1.03	$	0.87	$	1.98
Diluted	$	0.38	$	0.99	$	0.84	$	1.91

A summary of securities excluded from the computation of basic and diluted earnings per share is presented below for the applicable periods:

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2013		2012		2013		2012
	(In thousands)
Basic earnings per share:
Restricted stock		1,379		99		1,236		49
Diluted earnings per share:
Anti-dilutive stock options		1,127		1,215		1,126		1,200
Anti-dilutive restricted stock		655		99		328		49
Potentially dilutive securities excluded as anti-dilutive		1,782		1,314		1,454		1,249

Reclassifications

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

Note 2—Long-Term Debt and Capital Lease Obligations

Credit Facility

On April 19, 2011, the Company entered into a five-year $200.0 million senior secured revolving credit agreement, which was amended on June 5, 2012 and the borrowing base increased to $400.0 million (the “Credit Facility”). Loans under the Credit Facility are denominated in U.S. dollars and will

-9-

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTESTO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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 Consolidated Leverage Ratio, which is the ratio of funded indebtedness to EBITDA for the Company on a consolidated basis. The Company is also required to pay a quarterly commitment fee of 0.5% on the unused portion of the Credit Facility. As of June 30, 2013, $155.0 million was outstanding under the Credit Facility, along with $0.7 million in letters of credit, leaving $244.3 million available for borrowing. All obligations under the Credit Facility are guaranteed by the Company’s wholly-owned domestic subsidiaries, other than immaterial subsidiaries.

The Credit Facility contains customary affirmative and restrictive covenants including financial reporting, governance and notification requirements. Among other restrictions, the Company is unable to issue dividends under the terms of the Credit Facility. The Company was in compliance with all debt covenants under the Credit Facility as of June 30, 2013.

Capitalized terms used in this Note 2 – Long-Term Debt and Capital Lease Obligations but not defined herein are defined in the Credit Facility.

Capital Lease Obligations

The Company leases certain service equipment, with the intent to purchase, under non-cancelable capital leases. The terms of these contracts range from three to four years with varying payment dates throughout each month.

Note 3 – Intangible Assets

Intangible assets consist of the following (in thousands):

	Amortization Period	June 30,			December 31,
		2013			2012
Trade name	10 -15 years	$	27,275		$	27,275
Customer relationships	8-15 years		100,193			100,193
Non-compete	4 years		1,600			1,600
IPR&D	Indefinite		7,598			854
Trade name—Total	Indefinite		6,247			6,247
			142,913			136,169
Less: accumulated amortization			(17,716	)		(12,682	)
Intangible assets, net		$	125,197		$	123,487

Note 4 – Stock-Based Compensation

The C&J Energy Services, Inc. 2012 Long-Term Incentive Plan (the “2012 LTIP”) provides for the grant of stock-based awards to the Company’s officers, employees, consultants and non-employee directors. The following types of awards are available for issuance under the 2012 LTIP: incentive stock options and nonqualified stock options; stock appreciation rights; restricted stock; restricted stock units; dividend equivalent rights; and share awards. To date, only nonqualified stock options and restricted stock have been awarded under the 2012 LTIP. A total of 4,300,000 shares of common stock were authorized and approved for issuance under the 2012 LTIP, subject to certain adjustments. Of these shares, 3,053,835 shares were available for issuance under the 2012 LTIP as of June 30, 2013.

-10-

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTESTO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Prior to the approval of the 2012 LTIP, all stock-based awards granted to the Company’s employees were granted under the C&J Energy Services, Inc. 2010 Stock Option Plan (the “2010 Plan”), and prior to December 23, 2010, all stock-based awards granted to employees were granted under the C&J Energy Services, Inc. 2006 Stock Option Plan (the “2006 Plan” and, together with the 2010 Plan, the “Prior Plans”). Only nonqualified stock options were awarded under the Prior Plans. Effective as of December 23, 2010 and May 29, 2012, respectively, no additional awards will be granted under the 2006 Plan and the 2010 Plan.

Stock Options

The fair value of each option award granted under the 2012 LTIP and the Prior Plans is estimated on the date of grant using the Black-Scholes option-pricing model. Due to the Company’s lack of historical volume of option activity, the expected term of options granted is derived using the “plain vanilla” method. In addition, expected volatilities have been based on comparable public company data, with consideration given to the Company’s limited historical data. The Company makes estimates with respect to employee termination and forfeiture rates of the options within the valuation model. 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 totaling 133,597 grants during the six months ended June 30, 2012. No stock options were granted by the Company during the six months ended June 30, 2013.

	Six Months Ended
	June 30, 2012
Expected volatility	65% to 75%
Expected dividends	None
Exercise price	$16.88-$18.89
Expected term (in years)	6
Risk-free rate	0.9%-1.4%

As of June 30, 2013, the Company had 5,577,793 options outstanding to employees, consultants and non-employee directors. Options granted under the 2012 LTIP and the Prior Plans expire ten years from the date they are granted and generally vest over a three-year period.

Restricted Stock

Restricted stock is valued based on the closing price of the Company’s common stock on the date of grant. During the six months ended June 30, 2013, 725,756 shares of restricted stock were granted to employees, consultants and non-employee directors under the 2012 LTIP at fair market values ranging from $19.79 to $23.69 per share. A restricted stock recipient may, in satisfaction of his or her obligation to pay withholding taxes in connection with the vesting of an award, elect to make a cash payment to the Company or have withheld a portion of the shares then issuable to him or her, in either case having an aggregate fair market value equal to the withholding taxes.

-11-

Note 5 – Commitments and Contingencies

Hydraulic Fracturing Contracts

The Company has entered into multi-year take-or-pay contracts with certain customers. Under term contracts, customers are typically obligated to pay 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, the Company will be paid for the provision of such additional services based on rates stipulated in the contract. The revenue related to these contracts is recognized on the earlier of the passage of time under terms set forth in each contract or as the services are performed. As of June 30, 2013, the Company was providing hydraulic fracturing services under one term contract, which is scheduled to expire in early 2014.

Litigation

The Company is, and from time to time 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 pending or potential claims or litigation against the Company; however, management believes that the outcome of those matters that are presently known to the Company will not have a material adverse effect upon the Company’s consolidated financial position, results of operations or liquidity.

Note 6 – Segment Information

In accordance with FASB Accounting Standards Codification (“ASC”) 280 Segment Reporting, the Company routinely evaluates whether it has separate operating and reportable segments. The Company has determined that it operates in three reportable segments: Stimulation and Well Intervention Services, Wireline Services and Equipment Manufacturing. This determination is made based on the following factors: (1) the Company’s chief operating decision maker is currently managing each segment as a separate business and evaluating the performance of each segment 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 the Company’s three segments:

Stimulation and Well Intervention Services. This segment has two related service lines providing hydraulic fracturing services and coiled tubing and other well stimulation services.

Wireline Services. This segment provides cased-hole wireline services and other complementary services, including logging, perforating, pipe recovery, pressure testing and pumpdown services.

Equipment Manufacturing. This segment constructs equipment, conducts equipment repair services and provides oilfield parts and supplies for third-party customers in the energy services industry, as well as to fulfill the internal equipment demands of the Company’s Stimulation and Well Intervention Services and Wireline Services segments.

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.

-12-

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTESTO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

	Stimulation & Well Intervention Services		Wireline Services		Equipment Manufacturing		Corporate and Other			Total
	(in thousands)
Three months ended June 30, 2013
Revenue from external customers	$	197,737	$	67,661	$	1,558	$	—		$	266,956
Inter-segment revenues		14,214		3		11,643		(25,860	)		—
Adjusted EBITDA		48,370		19,711		1,198		(15,339	)		53,940
Depreciation and amortization		11,324		6,409		407		(214	)		17,926
Operating income (loss)		36,160		13,029		790		(15,124	)		34,855
Capital expenditures		21,302		8,059		271		12,857			42,489
Six months ended June 30, 2013
Revenue from external customers	$	410,424	$	129,790	$	2,793	$	—		$	543,007
Inter-segment revenues		25,792		3		30,343		(56,138	)		—
Adjusted EBITDA		102,648		37,361		3,072		(31,838	)		111,243
Depreciation and amortization		21,831		12,241		809		(399	)		34,482
Operating income (loss)		79,901		24,720		2,260		(31,608	)		75,273
Capital expenditures		46,701		20,468		541		11,751			79,461
As of June 30, 2013
Total assets	$	613,445	$	390,573	$	78,504	$	(10,524	)	$	1,071,998
Goodwill		64,703		131,455		4,718		—			200,876
Three months ended June 30, 2012
Revenue from external customers	$	252,022	$	15,125	$	11,241	$	—		$	278,388
Inter-segment revenues		13		—		17,144		(17,157	)		—
Adjusted EBITDA		95,969		4,677		4,878		(12,964	)		92,560
Depreciation and amortization		7,845		1,196		480		40			9,561
Operating income (loss)		87,557		3,481		4,396		(13,368	)		82,066
Capital expenditures		39,629		2,021		656		(3,200	)		39,106
Six months ended June 30, 2012
Revenue from external customers	$	478,567	$	15,125	$	23,748	$	—		$	517,440
Inter-segment revenues		13		—		32,985		(32,998	)		—
Adjusted EBITDA		187,604		4,677		8,568		(24,157	)		176,692
Depreciation and amortization		14,533		1,196		1,522		155			17,406
Operating income (loss)		172,504		3,481		7,045		(25,002	)		158,028
Capital expenditures		82,240		2,021		1,404		(7,800	)		77,865
As of June 30, 2012
Total assets	$	552,621	$	360,869	$	71,539	$	(9,468	)	$	975,561
Goodwill		60,339		129,905		4,718		—			194,962

Management evaluates segment performance and allocates resources based on total earnings before net interest expense, income taxes, depreciation and amortization, net gain or loss on disposal of assets, transaction costs, and non-routine items including loss on early extinguishment of debt, legal settlement charges and inventory write-down (“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 an operating measure, 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.

-13-

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTESTO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

As required under Item 10(e) of Regulation S-K of the Securities Exchange Act of 1934, as amended, 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						Six Months Ended
	June 30,						June 30,
	2013			2012			2013			2012
Adjusted EBITDA	$	53,940		$	92,560		$	111,243		$	176,692
Interest expense, net		(1,673	)		(891	)		(3,333	)		(1,271	)
Transaction costs		(3	)		(721	)		(176	)		(721	)
Provision for income taxes		(12,389	)		(27,900	)		(26,069	)		(54,031	)
Depreciation and amortization		(17,926	)		(9,561	)		(34,482	)		(17,406	)
Inventory write-down		(870	)		—			(870	)		—
Loss on disposal of assets		(232	)		(212	)		(322	)		(609	)
Net income	$	20,847		$	53,275		$	45,991		$	102,654

-14-

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 Securities Exchange Act of 1934, as amended (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 revenue, income and operating performance;

• our ability to sustain and improve our utilization and margins;

• our ability to enter into term contacts and/or pricing agreements at acceptable prices;

• our operating cash flows and availability of capital;

• our ability to execute our long-term growth strategy, including expansion into new geographic regions and business lines;

• 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;

• overcapacity and competition in our industry;

• increased pressures on pricing due to competition and economic conditions;

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

-15-

• unanticipated costs, delays, regulatory compliance requirements and other difficulties in executing our long-term growth strategy, including those related to expansion into new geographic regions and new business lines;

• 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;

• 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 revenue 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; and

• the potential failure to maintain effective internal control over financial reporting.

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, as well as in our Annual Report on Form 10-K for the fiscal year ended December 31, 2012 and (2) “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Part I, Item 2 of this Form 10-Q, as well as in our Annual Report on Form 10-K for the fiscal year ended December 31, 2012. 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, except as required by law.

-16-

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, together with the audited consolidated financial statements and notes thereto and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” included in our Annual Report on Form 10-K for the year ended December 31, 2012. Unless the context otherwise requires, “we,” “us,” the “Company,” “C&J” or like terms refers to C&J Energy Services, Inc. and its subsidiaries, including the financial results of Total and Casedhole Solutions (each as described below) from their respective acquisition dates.

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, wireline and other complementary services with a focus on complex, technically demanding well completions. These services are provided to oil and natural gas exploration and production companies throughout the United States. We also manufacture equipment, conduct equipment repairs and provide oilfield parts and supplies for third-party companies in the energy services industry, as well as to fulfill our internal needs. We operate in three reportable segments: Stimulation and Well Intervention Services, Wireline Services and Equipment Manufacturing. We provide hydraulic fracturing, coiled tubing and other well stimulation services through our Stimulation and Well Intervention Services segment. We provide cased-hole wireline and other complementary services through our Wireline Services segment, which we added in June 2012 with the acquisition of Casedhole Holdings, Inc. (together with its operating subsidiary, Casedhole Solutions, Inc., “Casedhole Solutions”). Through our Equipment Manufacturing segment, which we added with the acquisition of Total E&S Inc. (“Total”) in April 2011, we manufacture and repair equipment and provide oilfield parts and supplies for companies in the energy services industry. Through Total, we also fulfill our internal equipment demands and have centralized company-wide inventory management. Our three segments are described in more detail under “Our Operating Segments”.

Our Operating Segments

Stimulation and Well Intervention Services

Our Stimulation and Well Intervention Services segment provides hydraulic fracturing, coiled tubing and other well stimulation services, with a focus on complex, technically demanding well completions.

Hydraulic Fracturing Services. Our hydraulic fracturing business currently consists of more than 300,000 total horsepower capacity.

Our hydraulic fracturing operations contributed $160.5 million, or 60%, to our consolidated revenue and completed 1,577 fracturing stages during the second quarter of 2013, compared to $173.8 million of revenue and 1,698 fracturing stages during the first quarter of 2013. Hydraulic fracturing revenue for the second quarter of 2012 was $216.4 million and 1,667 fracturing stages were completed. During the three months ended June 30, 2013, we averaged monthly revenue per unit of horsepower of $195, compared to $218 for the first quarter of 2013 and $307 for the second quarter of 2012. The declines in total revenue and revenue per horsepower, as well as stages completed, in the second quarter

-17-

of 2013 compared to both the first quarter of 2013 and the second quarter of 2012 were primarily due to lower activity levels in a highly competitive pricing environment. Overall utilization varied throughout the second quarter, with a slight increase in activity in the latter half of the second quarter. Revenue and revenue per horsepower for the second quarter of 2013 were also negatively impacted by the transition from term contracts to new pricing agreements based on market terms with two of our contracted customers in early May, as described in more detail below.

We provide hydraulic fracturing services pursuant to term contracts and pricing agreements or on a spot market basis. Over the last several years, we entered into multi-year take-or-pay term contracts with certain customers, generally ranging from one year to three years. Under such term contacts, our customers are typically 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. Additionally, term contracts restrict the ability of the customer to terminate the contract in advance of its expiration date. With the scheduled expiration of a term contract as of June 30, 2013, currently, the Company is providing hydraulic fracturing services under one term contract, which is scheduled to expire in early 2014.

In May 2013, certain of our term contracts transitioned to new pricing agreements at or prior to their expiration. Under such pricing agreements our customers typically commit to targeted utilization levels at agreed pricing, but without termination penalties or obligations to pay for services not utilized by the customer. In addition, the agreed upon pricing is typically subject to periodic review, as specifically defined in the agreement, and may be adjusted to then-current market rates upon the agreement of both parties. For the three months ended June 30, 2013, we derived 42.7% of our consolidated revenue from hydraulic fracturing services performed under our term contracts and pricing agreements.

We charge prevailing market prices per hour for work performed in the spot market. We may also charge fees for setup and mobilization of equipment depending on the job, additional equipment used on the job, if any, and other miscellaneous consumables. 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. We charge our customers a fee for materials consumed in the process and a handling fee for any 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. Due to the flexibility of our operating model, our revenue can fluctuate without having a material impact to earnings when our customers elect to source their own consumables.

Coiled Tubing and Other Well Stimulation Services. Our coiled tubing business currently consists of 21 coiled tubing units. We have ordered three new coiled tubing units that we expect to be delivered in the third quarter of 2013.

Our coiled tubing operations contributed $32.5 million, or 12%, to our consolidated revenue, and we completed 944 coiled tubing jobs during the second quarter of 2013, compared to $36.4 million of revenue and 1,057 coiled tubing jobs for the first quarter of 2013 and $31.1 million and 866 coiled tubing jobs for the second quarter of 2012. Coiled tubing revenue decreased from the first quarter of 2013 as a result of lower activity levels coupled with increasingly competitive pricing. Utilization declined as a few of our core customers reduced their activity, and we encountered temporary disruptions in the Midcontinent and Bakken regions. An industry trend towards larger diameter coiled tubing also impacted demand for our services. Revenue and utilization improved in the second quarter of 2013 compared to the same quarter in 2012 due to the addition of new equipment.

Through our coiled tubing business, we also perform other well stimulation services, including pumpdown services for wireline and coiled tubing operations. These other services generated $4.7 million, or 2% of our consolidated revenue, during the second quarter of 2013, compared to $2.5 million for the previous quarter and $4.5 million for the prior year quarter. Revenue increased from the first quarter of 2013 due to a growth in activity levels for these services.

-18-

Our coiled tubing and other well stimulation services are generally provided in the spot market at prevailing prices per hour. 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.

Wireline Services Segment

Our Wireline Services segment, which we commenced with the acquisition of Casedhole Solutions on June 7, 2012, provides cased-hole wireline and other complementary services, including logging, perforating, pipe recovery, pressure testing and pumpdown services, which are critical throughout a well’s lifecycle. Our Wireline Services segment currently consists of 64 wireline units and 27 pumpdown units, as well as pressure control and other ancillary equipment. We currently plan to deploy five new wireline units during the remainder of 2013.

Our Wireline Services segment contributed $67.7 million, or 25%, to our consolidated revenue during the three months ended June 30, 2013, compared to $62.1 million in the first quarter of 2013 and $15.1 million in the second quarter of 2012. Revenue from wireline operations increased from the previous quarter due to improved utilization, as we added customers in new and existing areas of operation and increased utilization with current customers.

Services provided by this segment are generally provided at prevailing rates in the spot market on a job-by-job basis. The 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 have expertise in both horizontal and high-pressure, high-temperature completion applications and experience in the most complex and demanding operating environments, focusing on oily basins.

Equipment Manufacturing Segment

Our Equipment Manufacturing segment constructs oilfield equipment, including hydraulic fracturing pumps, coiled tubing units, pressure pumping units and wireline units, for third party customers in the energy services industry, as well as for our Stimulation and Well Intervention Services and Wireline Services segments. This segment also provides equipment repair services and oilfield parts and supplies to the energy services industry and to our Stimulation and Well Intervention Services and Wireline Services segments.

Our Equipment Manufacturing segment contributed $1.6 million, or 1%, to our consolidated revenue during the three months ended June 30, 2013, compared to $1.2 million of revenue for the first quarter of 2013 and $11.2 million of revenue for the second quarter of 2012. Our Equipment Manufacturing business has been negatively impacted by excess equipment capacity across the pressure pumping industry, a trend that we believe is likely to continue over the near term.

See Note 6 – Segment Information to the accompanying consolidated financial statements for further discussion regarding our reportable segments.

-19-

General Trends and Outlook

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 have taken steps to mitigate them to the extent practicable. In addition, while we believe that we are well positioned to capitalize on available growth opportunities, we may not be able to achieve our business objectives and, consequently, our results of operations may be adversely affected. Please read this section in conjunction with the factors described in the sections titled “Cautionary Note Regarding Forward-Looking Statements” and Part I, Item 1A “Risk Factors” for additional information about the known material risks that we face.

Trends that we believe are affecting, and will continue to affect, our industry include:

Competition & Demand for Our Services. Our business depends on the capital spending programs of our customers. Revenues from our Stimulation and Well Intervention Services and Wireline Services segments are generated by providing services to oil and natural gas exploration and production companies throughout the United States. The level of exploration, development and production activities by these customers also impacts demand for our Equipment Manufacturing segment’s services and products. Companies in the energy services industry have historically tended to delay capital equipment projects, including maintenance and upgrades, during industry downturns like the current one, which has been characterized by excess equipment capacity across the U.S. hydraulic fracturing market. The oil and gas industry has traditionally been volatile, is highly sensitive to supply and demand cycles and is influenced by a combination of long-term and cyclical trends, including the current and expected future prices for oil and natural gas and the perceived stability and sustainability of those prices, as well as production depletion rates and the resultant levels of cash flows generated and allocated by exploration and production companies to their drilling and workover budgets. The volatility of the oil and gas industry, and the consequent impact on exploration and production activity, has adversely impacted, and could continue to adversely impact, the level of drilling and workover activity by our customers. This volatility affects the demand for our services and our ability to negotiate pricing at levels generating desirable margins, especially in our hydraulic fracturing business.

The markets in which we operate are highly competitive. Our competition includes many large and small energy service companies, including the largest integrated energy services companies. The sustained price disparity between oil and natural gas on a Btu basis led to the migration of equipment from basins that are predominantly gas-related, and much of the current horizontal drilling and completion related activity is concentrated in oily- and liquids-rich formations. Our hydraulic fracturing operations encountered significant market pressure in the latter part of 2012, which continued through the first half of 2013 as a result of the overcapacity of completion equipment in our oily- and liquids-rich based operating areas, coupled with a lack of improvement in rig count. Commodity prices will likely continue to hamper drilling activities in natural gas shale plays over the near term. We believe that the hydraulic fracturing market will remain highly competitive for the remainder of 2013, and we do not expect either pricing or utilization to significantly improve without a significant increase in rig count.

All of our hydraulic fracturing equipment is now working in the spot market or under agreements that are reflective of current market rates, which has and may continue to result in lower pricing for our services and negatively impact our overall results. We are confident in our ability to successfully compete in and manage through the highly competitive operating environment. We are focused on improving utilization and expanding our customer base by targeting customers who recognize the value we provide through efficiency gains that result in significant cost savings to them. From a long term perspective, the industry’s shift towards more advanced completion methods and greater rig efficiency levels are well aligned with our core strengths. We believe we have sufficient resources in place to benefit from these long-term trends.

-20-

Hydraulic Fracturing Legislation and Regulation. Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, sand, and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production. The federal Energy Policy Act of 2005 amended the Underground Injection Control (“UIC”) provisions of the federal Safe Drinking Water Act (“SDWA”) to exclude hydraulic fracturing from the definition of “underground injection” and thereby exclude the process from direct federal regulation under the SDWA. The hydraulic fracturing process is currently typically regulated by state oil and natural gas commissions. However, the Environmental Protection Agency (“EPA”) has asserted federal regulatory authority over certain hydraulic fracturing activities involving the use of diesel, and has also adopted regulations requiring operators to capture rather than vent most gases that are brought to the surface during well completion activities, beginning in 2015. In addition, legislation has been introduced before Congress to provide for direct federal regulation of hydraulic fracturing and to require public disclosure of chemicals used in the hydraulic fracturing process. Also, many state governments have adopted, and other states are considering adopting, regulations that could impose more stringent permitting, public disclosure, well construction, and operational requirements on hydraulic fracturing operations or otherwise seek to temporarily or permanently ban fracturing activities altogether. In addition to state laws, local land use restrictions, such as city ordinances, may restrict or prohibit the performance of well drilling in general or hydraulic fracturing in particular.

In addition, certain governmental reviews are either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on water resources. The EPA’s study includes 18 separate research projects addressing topics such as water acquisition, chemical mixing, well injection, flowback and produced water, and waste water treatment and disposal. The EPA has indicated that it expects to issue its study report in late 2014. In the interim, however, the EPA has utilized existing statutory authority under the SDWA, the Clean Water Act, Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”) and the Clean Air Act (“CAA”) to investigate and pursue actions against some oil and natural gas producers where EPA believes their activities may have impacted air quality or groundwater. Moreover, the EPA is developing effluent limitations for the treatment and discharge of wastewater resulting from hydraulic fracturing activities and plans to propose these standards by 2014. On April 13, 2012, President Obama issued an executive order creating a task force to coordinate federal oversight over domestic natural gas production and hydraulic fracturing. Other governmental agencies, including the U.S. Department of Energy, have evaluated or are evaluating various aspects of hydraulic fracturing. These reviews and studies, depending on their results, could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory programs. Finally, the U.S. Department of Interior has proposed rules that would require oil and natural gas producers to publicly disclose their hydraulic fracturing chemicals in connection with drilling wells on federal and Indian lands and would also strengthen standards for well-bore integrity and the management of fluids that return to the surface during and after fracturing operations on federal and Indian lands.

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.

-21-

Results of Operations

Our results of operations are driven primarily by four interrelated variables: (1) the drilling and stimulation activities of our customers, which directly affects the demand for our services; (2) the prices we are able to charge for our services; (3) the cost of products, materials and labor, and our ability to pass those costs on to our customers; and (4) our service performance. With the majority of our hydraulic fracturing capacity now working in the spot market, the highly competitive operating and pricing environments for our services will dictate our level of profitability.

Through the first six months of 2013, the U.S. pressure pumping market continued to face challenging conditions. Our results for the three months ended June 30, 2013, were negatively impacted by lower activity levels and highly competitive pricing for our hydraulic fracturing services, as well as by the declines in revenue associated with the transition from term contracts to new pricing agreements based on market terms with two of our contracted customers in early May.

Results for the Three Months Ended June 30, 2013 Compared to the Three Months Ended June 30, 2012

The following table summarizes the change in our results of operations for the three months ended June 30, 2013 when compared to the three months ended June 30, 2012 (in thousands):

	Three Months Ended June 30,
	2013			2012			$ Change
Revenue	$	266,956		$	278,388		$	(11,432	)
Costs and expenses:
Direct Costs		180,370			168,322			12,048
Selling, general and administrative expenses		33,573			18,227			15,346
Depreciation and amortization		17,926			9,561			8,365
Loss on disposal of assets		232			212			20
Operating income		34,855			82,066			(47,211	)
Other income (expense):
Interest expense, net		(1,673	)		(891	)		(782	)
Other income (expense), net		54			—			54
Total other expenses, net		(1,619	)		(891	)		(728	)
Income before income taxes		33,236			81,175			(47,939	)
Provision for income taxes		12,389			27,900			(15,511	)
Net income	$	20,847		$	53,275		$	(32,428	)

Revenue

Revenue decreased $11.4 million, or 4%, to $267.0 million for the three months ended June 30, 2013, as compared to $278.4 million for the same period in 2012. This decrease was primarily related to a decrease of $56.0 million in the Stimulation and Well Intervention Services segment due to lower activity levels and pricing for our hydraulic fracturing services. Revenue for the second quarter of 2013 was also impacted by a decrease of $9.7 million in the Equipment Manufacturing segment due to lower third-party demand as a result of the current excess equipment capacity in the industry. However, our revenue for the second quarter of 2013 was positively impacted by an increase of $52.5 million in incremental Wireline Services revenue as a result of the acquisition of Casedhole Solutions in June 2012.

Direct Costs

Direct costs increased $12.0 million, or 7%, to $180.4 million for the three months ended June 30, 2013, compared to $168.3 million for the same period in 2012 primarily due to an increase of $30.3 million in the Wireline Services segment with the acquisition of Casedhole Solutions in June 2012, offset by a $12.2 million dollar decrease in the Stimulation and Well Intervention Services segment and a $7.5 million decrease in the Equipment Manufacturing segment due to a corresponding decrease in revenue. As a percentage of revenue, direct costs increased from 60.5% for the three months ended June 30, 2012 to 67.6% for the three months ended June 30, 2013 due to increased exposure to a highly competitive spot market in our hydraulic fracturing services.

-22-

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

SG&A increased $15.3 million, or 84%, to $33.6 million for the three months ended June 30, 2013, as compared to $18.2 million for the same period in 2012. The increase in SG&A was due to $7.3 million in increased costs related to Casedhole Solutions, which we acquired in June 2012, $4.6 million in higher payroll and personnel costs associated with the continued hiring of personnel to support the growth of our business and strategic initiatives, such as costs associated with vertical integration efforts across our service lines, the build out of our research and technology division and geographic expansion, and $2.1 million in higher long-term and short-term incentive costs. During the second quarter of 2013, we completed a review of our SG&A expenses and determined that certain costs, such as insurance costs associated with personnel charged to direct labor, are more appropriately reflected in direct costs on our consolidated statements of operations. This reclassification has been applied consistently to all periods presented in this Form 10-Q, including $3.2 million for the three months ended June 30, 2013 and $3.2 million for the same period in 2012.

Depreciation and Amortization

Depreciation and amortization expenses increased $8.4 million, or 87%, to $17.9 million for the three months ended June 30, 2013 as compared to $9.6 million for the same period in 2012. The increase was primarily related to $5.1 million from the Wireline Services segment due to the acquisition of Casedhole Solutions in June 2012 and $3.2 million from the Stimulation and Well Intervention Services segment due to the addition and deployment of new hydraulic fracturing and coiled tubing equipment.

Interest Expense

Interest expense increased by $0.8 million, or 88%, to $1.7 million for the three months ended June 30, 2013 as compared to $0.9 million for the same period in 2012. The increase was primarily attributable to higher average outstanding debt balances period over period. This debt was incurred to fund the June 2012 acquisition of Casedhole Solutions.

Income Taxes

We recorded a tax provision of $12.4 million for the three months ended June 30, 2013, at an effective rate of 37.3%, compared to a tax provision of $27.9 million for the three months ended June 30, 2012, at an effective rate of 34.4%. The increase in the effective tax rate is primarily due to lower pre-tax book income which caused state income taxes and the permanent differences between book and taxable income to have a higher proportionate impact on the calculation of the effective tax rate.

-23-

Results for the Six Months Ended June 30, 2013 Compared to the Six Months Ended June 30, 2012

The following table summarizes the change in our results of operations for the six months ended June 30, 2013 when compared to the six months ended June 30, 2012 (in thousands):

	Six Months Ended June 30,
	2013			2012			$ Change
Revenue	$	543,007		$	517,440		$	25,567
Costs and expenses:
Direct Costs		367,455			308,896			58,559
Selling, general and administrative expenses		65,475			32,501			32,974
Depreciation and amortization		34,482			17,406			17,076
Loss on disposal of assets		322			609			(287	)
Operating income		75,273			158,028			(82,755	)
Other income (expense):
Interest expense, net		(3,333	)		(1,271	)		(2,062	)
Other income (expense), net		120			(72	)		192
Total other expenses, net		(3,213	)		(1,343	)		(1,870	)
Income before income taxes		72,060			156,685			(84,625	)
Provision for income taxes		26,069			54,031			(27,962	)
Net income	$	45,991		$	102,654		$	(56,663	)

Revenue

Revenue increased $25.6 million, or 5%, to $543.0 million for the six months ended June 30, 2013, as compared to $517.4 million for the same period in 2012. This increase was primarily related to $114.7 million in incremental Wireline Services revenue as a result of the acquisition of Casedhole Solutions in June 2012. However, our revenue for the first six months of 2013 was negatively impacted by a decrease of $68.1 million in the Stimulation and Well Intervention Services segment primarily due to lower pricing for our hydraulic fracturing services, and a decrease of $21.0 million in the Equipment Manufacturing segment due to lower demand as a result of the current excess equipment capacity in the industry.

Direct Costs

Direct costs increased $58.6 million, or 19%, to $367.5 million for the six months ended June 30, 2013, compared to $308.9 million for the same period in 2012 primarily due to an increase of $65.8 million in the Wireline Services segment with the acquisition of Casedhole Solutions in June 2012 and an increase of $7.7 million in the Stimulation and Well Interventions Services segment due to higher activity levels as a result of added equipment capacity. These increases were offset by a decrease of $16.6 million in the Equipment Manufacturing segment as a result of lower third-party sales. As a percentage of revenue, direct costs increased from 59.7% for the six months ended June 30, 2012 to 67.7% for the six months ended June 30, 2013 due to increased exposure to a highly competitive spot market in our hydraulic fracturing services.

SG&A Expense

SG&A increased $33.0 million, or 101%, to $65.5 million for the six months ended June 30, 2013, as compared to $32.5 million for the same period in 2012. The increase was due to $16.3 million in increased costs related to Casedhole Solutions, which we acquired in June 2012, $8.6 million in higher payroll and personnel costs associated with the continued hiring of personnel to support the growth of our business and strategic initiatives, such as costs associated with vertical integration efforts across our service lines, the build out of our research and technology division and geographic expansion, $4.2 million in higher long-term and short-term incentive costs, $1.1 million in higher property taxes and $1.1 million in higher professional fees and marketing costs. During the second quarter of 2013, we completed a review of our SG&A expenses and determined that certain costs, such as insurance costs associated with personnel charged to direct labor, are more appropriately reflected in direct costs on our consolidated statements of operations. This reclassification has been applied consistently to all periods presented in this Form 10-Q, including $8.4 million for the six months ended June 30, 2013 and $5.7 million for the same period in 2012.

-24-

Depreciation and Amortization

Depreciation and amortization expenses increased $17.1 million, or 98%, to $34.5 million for the six months ended June 30, 2013 as compared to $17.4 million for the same period in 2012. The increase was primarily related to $10.9 million from the Wireline Services segment due to the acquisition of Casedhole Solutions in June 2012 and $6.6 million from the Stimulation and Well Intervention Services segment due to the addition and deployment of new hydraulic fracturing and coiled tubing equipment, partially offset by a $0.7 million decrease from the Equipment Manufacturing segment due to the full amortization of certain intangible assets in April 2012.

Interest Expense

Interest expense increased by $2.1 million, or 162%, to $3.3 million for the six months ended June 30, 2013 as compared to $1.3 million for the same period in 2012. The increase was primarily attributable to higher average outstanding debt balances period over period. This debt was incurred to fund the June 2012 acquisition of Casedhole Solutions.

Income Taxes

We recorded a tax provision of $26.1 million for the six months ended June 30, 2013, at an effective rate of 36.2%, compared to a tax provision of $54.0 million for the six months ended June 30, 2012, at an effective rate of 34.5%. The increase in the effective tax rate is primarily due to lower pre-tax book income, which caused state income taxes and the permanent differences between book and taxable income to have a higher proportionate impact on the calculation of the effective tax rate.

Liquidity and Capital Resources

Since the beginning of 2011, our primary sources of liquidity have been cash flows from operations, borrowings under our credit facilities and the net proceeds that we received from our IPO, which closed on August 3, 2011. Our primary uses of capital during this period were for the expansion of our operations, including the purchase and maintenance of equipment and the acquisitions of Casedhole Solutions and Total. Our capital expenditures and our maintenance costs have increased substantially over the last few years to support our growth, and we expect this trend to continue on a long-term basis as we continue to focus on expanding geographically, while actively exploring opportunities to enhance our current business and evaluating complementary service lines in an effort to further diversify our product offerings. The successful execution of our long-term growth strategy depends on our ability to raise capital as needed. We believe that we are well-positioned to capitalize on available opportunities and finance future growth, although sustained pressure on pricing and decreased utilization for our hydraulic fracturing services could lead to reduced capital expenditures.

Our Credit Facility (as defined and described in more detail under “Description of Our Indebtedness” and in Note 2 – Long-Term Debt and Capital Lease Obligations to the accompanying consolidated financial statements) provides for up to $400.0 million of revolving credit, which was increased from $200.0 million in June 2012. As of June 30, 2013, we had $155.0 million outstanding under the Credit Facility and $0.7 million in letters of credit, and as of August 2, 2013, we had $150.0 million outstanding along with $0.7 million in letters of credit, leaving $249.3 million available for additional borrowings at that date. 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, as well as certain limitations on our ability to make capital expenditures on a fiscal year basis. These covenants are subject to a number of exceptions and qualifications. As of June 30, 2013, we were in compliance with these covenants.

-25-

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 from operations and existing capital, coupled with borrowings available under our Credit Facility, will be adequate to meet operational and capital expenditure needs over the next twelve months.

Capital Requirements

The energy services business is capital-intensive, requiring significant investment to maintain, upgrade and purchase additional equipment to meet our customers’ needs and industry demand. Capital expenditures totaled $79.5 million in the first six months of 2013, the majority of which was for new equipment. Our remaining 2013 capital expenditures are expected to range from $40 to $50 million based on current equipment orders and growth estimates. We increased 2013 planned capital expenditures for the addition of new wireline capacity and related infrastructure, as well as new equipment to support our existing coiled tubing and hydraulic fracturing operations. We expect that the majority our 2013 capital expenditures will be spent on the continuing execution of our growth strategy, including the investments in new equipment and maintenance capital for these three service lines. We intend to fund our remaining 2013 capital expenditures with cash flows from operations.

We continually monitor new advances in equipment and down-hole technology, as well as new technologies and products that may complement and enhance our existing businesses. During the first half of 2013, we significantly enhanced our research and development capabilities through our recently established research and technology division. We will continue to invest in the build-out of this division as we focus on identifying services and tools that will enable us to more effectively compete against larger integrated energy services companies.

Additionally, we are actively evaluating opportunities to further enhance and grow our business, including through selective acquisitions and targeted expansion, domestically and internationally. With respect to our international expansion efforts, we are investing in the infrastructure needed to capitalize on available opportunities and support future operations. As we pursue compelling opportunities, we will continue to make capital investment decisions that we believe will support our long-term growth strategy.

We believe we are well positioned to finance our future growth. Despite the highly competitive environment, which has impacted pricing and activity levels, we have continued to generate strong cash flows. On June 5, 2012, we increased the borrowing base under our Credit Facility to $400.0 million from $200.0 million and as of August 2, 2013, $249.3 million was available for borrowing. We believe our cash flows from operations and existing capital, coupled with borrowings under our Credit Facility, if needed, will be sufficient to fund our 2013 capital expenditures and sustain our spending levels over the next twelve months. We plan to continue to monitor the economic environment and demand for our services and adjust our business strategy as necessary.

-26-

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,
	2013			2012
Cash provided by (used in):
Operating activities	$	95,465		$	92,607
Investing activities		(86,395	)		(349,549	)
Financing activities		(10,841	)		218,440
Change in cash and cash equivalents	$	(1,771	)	$	(38,502	)

Cash Provided by Operating Activities

Net cash provided by operating activities increased $2.9 million for the six months ended June 30, 2013 as compared to the same period in 2012. This increase was primarily due to an increase in depreciation and amortization and working capital fluctuations, offset by lower net income.

Cash Used in Investing Activities

Net cash used in investing activities decreased $263.2 million for the six months ended June 30, 2013 as compared to the same period in 2012. This decrease was due primarily to the cash paid to acquire Casedhole Solutions in 2012.

Cash Provided by Financing Activities

Net cash used in financing activities was $10.8 million for the six months ended June 30, 2013 compared to net cash provided by financing activities of $218.4 million for the same period in 2012. Cash used in financing activities for the year to date 2013 primarily consisted of $15.0 million to pay down a portion of the balance outstanding under the Credit Facility. Cash provided by financing activities for the year to date 2012 primarily consisted of a $220.0 million draw on the Credit Facility to partially fund the acquisition of Casedhole Solutions.

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, 2013.

Description of Our Indebtedness

Credit Facility. 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 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 (“Credit Facility”). Obligations under the Credit Facility are guaranteed by our wholly-owned domestic subsidiaries (the “Guarantor Subsidiaries”), other than immaterial subsidiaries. Effective June 5, 2012, in connection with the acquisition of Casedhole Solutions, we entered into Amendment No. 1 and Joinder to Credit Agreement (the “Amendment”) primarily to facilitate and permit us to fund a portion of the purchase price of the Casedhole Solutions acquisition.

The Amendment increased our borrowing capacity under the Credit Facility to $400.0 million. To effectuate this increase, new financial institutions were added to the Credit Facility as lenders and certain existing lenders severally agreed to increase their respective commitments. Pursuant to the Amendment, the aggregate amount by which we may periodically increase commitments through incremental facilities was increased from $75.0 million to $100.0 million, the sublimit for letters of credit was left unchanged at

-27-

$200.0 million and the sublimit for swing line loans was increased from $15.0 million to $25.0 million. On June 7, 2012, we drew $220.0 million from the Credit Facility to fund a portion of the purchase price of the Casedhole Solutions acquisition. As of June 30, 2013, we had $155.0 million outstanding under the Credit Facility and $0.7 million in letters of credit, and as of August 2, 2013, we had $150.0 million outstanding along with $0.7 million in letters of credit, leaving $249.3 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 Consolidated Leverage Ratio. The Consolidated 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 the Guarantor Subsidiaries.

The Credit Facility contains customary affirmative covenants including financial reporting, governance and notification requirements. The Amendment made certain changes to the Credit Facility’s affirmative covenants, including the financial reporting and notification requirements, and the Credit Facility’s negative covenants, including the restriction on our ability to conduct asset sales, incur additional indebtedness, issue dividends, grant liens, issue guarantees, make investments, loans or advances and enter into certain transactions with affiliates. Additionally, the Amendment altered the restriction on capital expenditures to allow us to make an unlimited amount of capital expenditures so long as (i) the pro forma Consolidated Leverage Ratio is less than 2.00 to 1.00, (ii) we have pro forma liquidity of greater than $40.0 million, (iii) no default exists and (iv) the capital expenditures could not reasonably be expected to cause a default. Further, in the event that these conditions are not met, we will be permitted to make capital expenditures of up to $200.0 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 may be pulled forward from the subsequent fiscal year. These capital expenditure restrictions do not apply to capital expenditures financed solely with the proceeds from the issuance of qualified equity interests and asset sales or normal replacement and maintenance capital expenditures.

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 Consolidated Leverage Ratio of not greater than 3.25 to 1.00. As of June 30, 2013, we were in compliance with all debt covenants.

Capitalized terms used in “Description of Our Indebtedness” but not defined herein are defined in the Credit Facility.

ITEM 3. QUANTITATIVEAND QUALITATIVE DISCLOSURES 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.

-28-

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, 2013.

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, 2013 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

-29-

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 risks described below and 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” in our Annual Report on Form 10-K for the year ended December 31, 2012 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.

We could be adversely affected by violations of the U.S. Foreign Corrupt Practices Act and similar foreign anti-bribery laws.

The United States Foreign Corrupt Practices Act (the “FCPA”) and similar worldwide anti-bribery laws generally prohibit companies and their intermediaries from making, offering or authorizing improper payments to non-U.S. government officials for the purpose of obtaining or retaining business. We do business and may do additional business in the future in countries or regions where strict compliance with anti-bribery laws may conflict with local customs and practices. Violations of anti-bribery laws (either due to our acts or our inadvertence) may result in criminal and civil sanctions and could subject us to other liabilities in the U.S. and elsewhere. Even allegations of such violations could disrupt our business and result in a material adverse effect on our business and operations.

We are committed to doing business in accordance with applicable anti-corruption laws and our own internal policies and procedures. We have implemented policies and procedures concerning compliance with the FCPA that is disseminated to employees, directors, contractors, and agents. This policy has been implemented as part of our anti-bribery compliance program.

Our existing safeguards and any future improvements, however, may prove to be less than effective, and our employees and consultants may engage in conduct for which we might be held responsible. Some foreign jurisdictions may require us to utilize local agents and/or establish joint ventures with local operators or strategic partners. Even though some of our agents and partners may not themselves be subject to the FCPA or other non-U.S. anti-bribery laws to which we may be subject, if our agents or partners make improper payments to non-U.S. government officials in connection with engagements or partnerships with us, we could be investigated and potentially found liable for violation of such anti-bribery laws and could incur civil and criminal penalties and other sanctions, which could have a material adverse effect on our business, financial position, results of operations and cash flows.

-30-

ITEM 2. UNREGISTERED SALESOF EQUITY SECURITIESAND USEOF PROCEEDS

The following table summarizes stock repurchase activity for the six months ended June 30, 2013 (in thousands, except average price paid per share):

Period	Total Number of Shares Purchased (a)		Average Price Paid Per Share		Total Number of Shares Purchased as Part of Publicly Announced Program		Maximum Number of Shares that may yet be Purchased Under Such Program
January 1—January 31		—		—		—		—
February 1—February 28		2,415		23.69		—		—
March 1—March 31		—		—		—		—
April 1—April 30		—		—		—		—
May 1—May 31		—		—		—		—
June 1—June 30		62,300		18.98		—		—

(a) Represents shares that were withheld by us to satisfy tax withholding obligations of employees that arose upon the vesting of restricted stock. The value of such shares is based on the closing price of our common stock on the vesting date.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

ITEM 5. OTHER INFORMATION

None.

-31-

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.

-32-

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, 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: August 6, 2013		By:	/s/ Randall C. McMullen, Jr.
		Randall C. McMullen, Jr.
		President, Chief Financial Officer
		and Treasurer
		(Duly Authorized Officer and Principal
		Financial Officer)

-33-

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.

-34-