C&J Energy Services, Inc. - FORM 10-Q

Attached files

file	filename
EX-32.2 - EXHIBIT 32.2 - C&J Energy Services, Inc.	cjes63018ex322.htm
EX-32.1 - EXHIBIT 32.1 - C&J Energy Services, Inc.	cjes63018ex321.htm
EX-31.2 - EXHIBIT 31.2 - C&J Energy Services, Inc.	cjes63018ex312.htm
EX-31.1 - EXHIBIT 31.1 - C&J Energy Services, Inc.	cjes63018ex311.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q



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

For the quarterly period ended June 30, 2018



¨	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: 000-55404

C&J Energy Services, Inc.

(Exact name of registrant as specified in its charter)



Delaware		81-4808566
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

3990 Rogerdale Rd.

Houston, Texas 77042

(Address of principal executive office)

(713) 325-6000

(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 ý 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 ý No ¨

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



Large accelerated filer	ý	Accelerated filer	¨

Non-accelerated filer	¨ (Do not check if a smaller reporting company)	Smaller reporting company	¨

		Emerging growth company	¨

If an emerging growth company, indicated by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨

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

Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Sections 12, 13, or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court. Yes ý No ¨

The number of shares of the registrant’s common stock, par value $0.01 per share, outstanding at August 3, 2018, was 68,357,617.

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, 2018 and December 31, 2017	1
	Consolidated Statements of Operations for the three months ended June 30, 2018 and 2017	2
	Consolidated Statements of Operations for the six months ended June 30, 2018 and 2017 (Successor) and on January 1, 2017 (Predecessor)	3
	Consolidated Statements of Comprehensive Income (Loss) for the three and six months ended June 30, 2018 and 2017 (Successor) and on January 1, 2017 (Predecessor)	4
	Consolidated Statements of Changes in Stockholders' Equity for the year ended December 31, 2017 (Predecessor), on January 1, 2017 (Successor) and for the six months ended June 30, 2018 (Successor)	5
	Consolidated Statements of Cash Flows for the six months ended June 30, 2018 and 2017 (Successor), and on January 1, 2017 (Predecessor)	6
	Notes to Consolidated Financial Statements	7
	Cautionary Note Regarding Forward-Looking Statements	29
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	31
	Reportable Segments	32
	Operating Overview	35
	Results of Operations	41
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	51
Item 4.	Controls and Procedures	51
PART II – OTHER INFORMATION
Item 1.	Legal Proceedings	52
Item 1A.	Risk Factors	52
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	52
Item 3.	Defaults Upon Senior Securities	52
Item 4.	Mine Safety Disclosures	52
Item 5.	Other Information	52
Item 6.	Exhibits	53
	Signatures	54

-i-

PART I – FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In thousands, except share data)



	June 30, 2018			December 31, 2017
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	110,042		$	113,887
Accounts receivable, net of allowance of $5,002 at June 30, 2018 and $4,269 at December 31, 2017	411,165			367,906
Inventories, net	83,092			77,793
Prepaid and other current assets	32,503			33,011
Total current assets	636,802			592,597
Property, plant and equipment, net of accumulated depreciation of $227,160 at June 30, 2018 and $133,755 at December 31, 2017	746,814			703,029
Other assets:
Goodwill	146,015			147,515
Intangible assets, net	119,445			123,837
Deferred financing costs, net of accumulated amortization of $2,464 at June 30, 2018 and $608 at December 31, 2017	4,667			3,379
Other noncurrent assets	28,967			38,500
Total assets	$	1,682,710		$	1,608,857
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	187,166		$	138,624
Payroll and related costs	41,014			52,812
Accrued expenses	59,110			67,414
Total current liabilities	287,290			258,850
Deferred tax liabilities	2,560			3,917
Other long-term liabilities	26,464			24,668
Total liabilities	316,314			287,435
Commitments and contingencies
Stockholders' equity
Common stock, par value of $0.01, 1,000,000,000 shares authorized, 68,386,944 and 68,546,820 issued and outstanding at June 30, 2018 and December 31, 2017, respectively	684			686
Additional paid-in capital	1,307,585			1,298,859
Accumulated other comprehensive loss	(260		)	(580		)
Retained earnings	58,387			22,457
Total stockholders' equity	1,366,396			1,321,422
Total liabilities and stockholders’ equity	$	1,682,710		$	1,608,857

See accompanying notes to consolidated financial statements

-1-

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per share data)



	Three Months Ended June 30, 2018			Three Months Ended June 30, 2017
	(Unaudited)
Revenue	$	610,521		$	390,143
Costs and expenses:
Direct costs	463,602			310,473
Selling, general and administrative expenses	59,908			61,165
Research and development	1,681			2,052
Depreciation and amortization	54,387			32,833
(Gain) loss on disposal of assets	49			(3,136		)
Operating income (loss)	30,894			(13,244		)
Other income (expense):
Interest expense, net	(2,185		)	(414		)
Other income (expense), net	(1,106		)	(1,456		)
Total other income (expense)	(3,291		)	(1,870		)

Income (loss) before income taxes	27,603			(15,114		)
Income tax benefit	(893		)	(2,393		)
Net income (loss)	$	28,496		$	(12,721	)
Net income (loss) per common share:
Basic	$	0.42		$	(0.20	)
Diluted	$	0.42		$	(0.20	)
Weighted average common shares outstanding:
Basic	67,268			62,232
Diluted	67,268			62,232

See accompanying notes to consolidated financial statements

-2-

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per share data)



	Successor						Predecessor
	Six Months Ended June 30, 2018			Six Months Ended June 30, 2017			On January 1, 2017
	(Unaudited)
Revenue	$	1,163,521		$	704,337		$	—
Costs and expenses:
Direct costs	882,599			572,216			—
Selling, general and administrative expenses	125,843			123,257			—
Research and development	3,553			3,269			—
Depreciation and amortization	100,730			64,439			—
Gain on disposal of assets	(440		)	(9,192		)	—
Operating income (loss)	51,236			(49,652		)	—
Other income (expense):
Interest expense, net	(2,613		)	(1,105		)	—
Other income (expense), net	(486		)	106			—
Total other income (expense)	(3,099		)	(999		)	—

Income (loss) before reorganization items and income taxes	48,137			(50,651		)	—
Reorganization items	—			—			(293,969		)
Income tax benefit	(953		)	(5,629		)	(4,613		)
Net income (loss)	$	49,090		$	(45,022	)	$	298,582
Net income (loss) per common share:
Basic	$	0.73		$	(0.76	)	$	2.52
Diluted	$	0.73		$	(0.76	)	$	2.52
Weighted average common shares outstanding:
Basic	67,227			58,913			118,633
Diluted	67,267			58,913			118,633

See accompanying notes to consolidated financial statements

-3-

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(In thousands)



	Three Months Ended June 30, 2018		Three Months Ended June 30, 2017
	(Unaudited)
Net income (loss)	$	28,496	$	(12,721	)

Other comprehensive income (loss):
Foreign currency translation gain, net of tax	690		409
Comprehensive income (loss)	$	29,186	$	(12,312	)



	Successor					Predecessor
	Six Months Ended June 30, 2018		Six Months Ended June 30, 2017			On January 1, 2017
	(Unaudited)
Net income (loss)	$	49,090	$	(45,022	)	$	298,582

Other comprehensive income (loss):
Foreign currency translation gain (loss), net of tax	320		(304		)	—
Comprehensive income (loss)	$	49,410	$	(45,326	)	$	298,582

See accompanying notes to consolidated financial statements

-4-

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY

(In thousands)



	Common Stock					Additional Paid-in Capital			Other Comprehensive Loss			Retained Earnings (Deficit)			Total
	Number of Shares		Amount, at $0.01 par value			Additional Paid-in Capital			Other Comprehensive Loss			Retained Earnings (Deficit)			Total
Balance, December 31, 2016 (Predecessor)	119,530		1,195			1,009,426			(2,600		)	(1,306,591		)	(298,570		)
Cancellation of Predecessor equity	(119,530	)	(1,195		)	(1,009,426		)	2,600			1,306,591			298,570


Issuance of New Equity and New Warrants	40,000		400			725,464			—			—			725,864
Rights Offering	15,464		155			199,845			—			—			200,000
Balance, January 1, 2017 (Successor)	55,464		555			925,309			—			—			925,864
Public offering of common stock, net of offering costs	7,050		71			215,849			—			—			215,920
Issuance of stock for business acquisition	4,420		44			138,122			—			—			138,166
Issuance of restricted stock, net of forfeitures	1,718		17			(17		)	—			—			—
Exercise of warrants	2		—			—			—			—			—
Employee tax withholding on restricted stock vesting	(107	)	(1		)	(3,841		)	—			—			(3,842		)
Share-based compensation	—		—			23,437			—			—			23,437
Net income	—		—			—			—			22,457			22,457
Foreign currency translation loss, net of tax	—		—			—			(580		)	—			(580		)
Balance, December 31, 2017 (Successor)	68,547		$	686		$	1,298,859		$	(580	)	$	22,457		$	1,321,422
Cumulative effect from change in accounting principle	—		—			—			—			(13,160		)	(13,160		)
Issuance of restricted stock, net of forfeitures	(80	)	(1		)	1			—			—			—
Employee tax withholding on restricted stock vesting	(80	)	(1		)	(2,192		)	—			—			(2,193		)
Share-based compensation	—		—			10,917			—			—			10,917
Net income	—		—			—			—			49,090			49,090
Foreign currency translation gain, net of tax	—		—			—			320			—			320
Balance, June 30, 2018 (Successor) *	68,387		684			1,307,585			(260		)	58,387			1,366,396



*	Unaudited

See accompanying notes to consolidated financial statements

-5-

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)



	Successor						Predecessor
	Six Months Ended June 30, 2018			Six Months Ended June 30, 2017			On January 1, 2017
	(Unaudited)
Cash flows from operating activities:
Net income (loss)	$	49,090		$	(45,022	)	$	298,582
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation and amortization	100,730			64,439			—
Deferred income taxes	(1,112		)	—			(4,613		)
Provision for doubtful accounts	1,497			2,032			—
Equity (earnings) loss from unconsolidated affiliate	1,199			(153		)	—
Gain on disposal of assets	(440		)	(9,192		)	—
Share-based compensation expense	10,917			19,541			—
Amortization of deferred financing costs	1,856			306			—
Reorganization items, net	—			—			(315,626		)
Changes in operating assets and liabilities:
Accounts receivable	(46,408		)	(159,643		)	—
Inventories	(6,020		)	(6,978		)	—
Prepaid expenses and other current assets	2,933			6,741			—
Accounts payable	40,239			27,784			—
Payroll related costs and accrued expenses	(23,077		)	6,747			(1,436		)
Liabilities subject to compromise	—			—			(33,000		)
Income taxes receivable (payable)	4,215			(5,200		)	—
Other	(892		)	1,744			—
Net cash provided by (used in) operating activities	134,727			(96,854		)	(56,093		)
Cash flows from investing activities:
Purchases of and deposits on property, plant and equipment	(155,790		)	(72,547		)	—
Proceeds from disposal of property, plant and equipment and non-core service lines	20,862			31,182			—
Business acquisition purchase price adjustment	1,500			—			—
Net cash used in investing activities	(133,428		)	(41,365		)	—
Cash flows from financing activities:
Payments on DIP Facility	—			—			(25,000		)
Financing costs	(3,144		)	(1,463		)	(2,248		)
Proceeds from issuance of common stock, net of offering costs	—			215,920			200,000
Employee tax withholding on restricted stock vesting	(2,193		)	(3,870		)	—
Net cash provided by (used in) financing activities	(5,337		)	210,587			172,752

Effect of exchange rate changes on cash	193			(855		)	—
Net increase (decrease) in cash and cash equivalents	(3,845		)	71,513			116,659
Cash and cash equivalents, beginning of period	113,887			181,242			64,583
Cash and cash equivalents, end of period	$	110,042		$	252,755		$	181,242

See accompanying notes to consolidated financial statements

-6-

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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

Organization and Nature of Business

C&J Energy Services, Inc., a Delaware corporation (the “Successor” and together with its consolidated subsidiaries for periods subsequent to the Plan Effective Date (as defined in Note 2 - Chapter 11 Proceeding and Emergence), “C&J” or the “Company”), is a leading provider of well construction and intervention, well completion, well support and other complementary oilfield services and technologies to independent and major oil field companies engaged in the exploration, production and development of oil and gas properties in onshore basins throughout the continental United States. The Company is a new well-focused service provider offering a diverse, integrated suite of services across the life cycle of the well, including hydraulic fracturing, cased-hole wireline and pumping, cementing, coiled tubing, rig services, fluids management and other completions-focused and specialty well site support services.

The Company was founded in Texas in 1997 and is headquartered in Houston, Texas. On April 12, 2017, following the successful completion of a financial restructuring (see Note 2 - Chapter 11 Proceeding and Emergence), the Company completed an underwritten public offering of common stock and began trading on the New York Stock Exchange (“NYSE”) under the symbol “CJ.”

Summary of Significant Accounting Policies

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, 2017, the consolidated statements of operations, comprehensive income (loss), and cash flows on January 1, 2017, and the consolidated statement of changes in stockholders' equity as of December 31, 2016, January 1, 2017 and December 31, 2017, are derived from audited consolidated financial statements. In the opinion of management, all material adjustments, consisting of normal recurring adjustments, necessary for fair presentation have been included. These consolidated financial statements include all accounts of the Company. All significant intercompany transactions and accounts have been eliminated upon consolidation.

These consolidated financial statements have been prepared pursuant to the rules and regulations of the U.S. 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 fiscal year ended December 31, 2017, which are included in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2017 filed with the SEC. 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.

On January 1, 2017 (the "Fresh Start Reporting Date"), in connection with the Company's emergence from its Chapter 11 Proceeding (as defined in Note 2 - Chapter 11 Proceeding and Emergence), the Company adopted fresh start accounting in accordance with Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 852 - Reorganizations, in preparing the consolidated financial statements. ASC 852 requires that the financial statements distinguish transactions and events that are directly associated with the Chapter 11 Proceeding from the ongoing operations of the business. Accordingly, certain expenses, gains and losses that were realized or incurred in the Chapter 11 Proceeding were recorded in a reorganization line item on the consolidated statements of operations. The Company's consolidated financial statements and notes on January 1, 2017, are not comparable to the consolidated financial statements for the periods subsequent to January 1, 2017, due to the application of fresh start accounting as noted above.

Reclassifications. Certain reclassifications have been made to prior period amounts to conform to current period financial statement presentation. These reclassifications did not affect previously reported results of operations, stockholders' equity, comprehensive income or cash flows.

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.

-7-

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Estimates are used in, but are not limited to, determining the following: allowance for doubtful accounts, valuation of long-lived assets and intangibles, goodwill, useful lives used in depreciation and amortization, inventory reserves, income taxes and share-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, or as additional information is obtained and as the Company’s operating environment changes.

Cash and Cash Equivalents. For purposes of the consolidated statement of cash flows, cash is defined as cash on-hand, demand deposits and short-term investments with initial maturities of three months or less. The Company maintains its cash and cash equivalents in various financial institutions, which at times may exceed federally insured amounts. Management believes that this risk is not significant. Cash balances related to the Company's captive insurance subsidiaries, which totaled $9.6 million and $23.8 million at June 30, 2018 and December 31, 2017, respectively, are included in cash and cash equivalents in the consolidated balance sheets, and the Company expects to use these cash balances to fund the day to day operations of the captive insurance subsidiaries and to settle future anticipated claims.

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

Inventories. Inventories are carried at the lower of cost or net realizable value using a weighted average cost flow method. Inventories for the Company consist of raw materials, work-in-process and finished goods, including equipment components, chemicals, proppants, supplies and materials for the Company's operations.

Inventories consisted of the following (in thousands):



	June 30, 2018			December 31, 2017
Raw materials	$	3,544		$	5,302
Work-in-process	664			1,329
Finished goods	81,919			74,552
Total inventory	86,127			81,183
Inventory reserve	(3,035		)	(3,390		)
Inventory, net	$	83,092		$	77,793

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

PP&E are evaluated on a quarterly basis to identify events or changes in circumstances (“triggering events”) that indicate the carrying value of certain PP&E may not be recoverable. PP&E are reviewed for impairment upon the occurrence of a triggering event. An impairment loss is recorded in the period in which it is determined that the carrying amount of PP&E is not recoverable. The determination of recoverability is made based upon the estimated undiscounted future net cash flows of assets grouped at the lowest level for which there are identifiable cash flows independent of the cash flows of other groups of assets with such cash flows to be realized over the estimated remaining useful life of the primary asset within the asset group, excluding interest expense. The Company determined the lowest level of identifiable cash flows that are independent of other asset groups to be primarily at the service line level. The Company's asset groups consist of the well support services, fracturing, cased-hole wireline and pumping services, cementing, coiled tubing, and data acquisition and control instruments provider service lines as well as the research and technology ("R&T") service lines. If the estimated undiscounted future net cash flows for a given asset group is less than the carrying amount of the related assets, an impairment loss is determined by comparing the estimated fair value with the carrying value of the related assets. The impairment loss is then allocated across the asset group's major classifications. No impairment charge was recorded for the six months ended June 30, 2018 and 2017.

Goodwill and Definite-Lived Intangible Assets. Goodwill may be allocated across three reporting units:

-8-

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Completion Services, Well Construction and Intervention Services ("WC&I") and Well Support Services. At the reporting unit level, the Company tests goodwill for impairment on an annual basis as of October 31 of each year, or when events or changes in circumstances, referred to as triggering events, indicate the carrying value of goodwill may not be recoverable and that a potential impairment exists.

Judgment is used in assessing whether goodwill should be tested for impairment more frequently than annually. Factors such as unexpected adverse economic conditions, competition, market changes and other external events may require more frequent assessments.

Before employing quantitative impairment testing methodologies, the Company may first evaluate the likelihood of impairment by considering qualitative factors relevant to each reporting unit, such as macroeconomic, industry, market or any other factors that have a significant bearing on fair value. If the Company first utilizes a qualitative approach and determines that it is more likely than not that goodwill is impaired, quantitative testing methodologies are then applied. Otherwise, the Company concludes that no impairment has occurred. Quantitative impairment testing involves comparing the fair value of each reporting unit to its carrying value, including goodwill. Fair value reflects the price a market participant would be willing to pay in a potential sale of the reporting unit. If the fair value exceeds carrying value, then it is concluded that no goodwill impairment has occurred. If the carrying value of the reporting unit exceeds its fair value an impairment loss is recognized in an amount equal to the excess, not to exceed the amount of goodwill allocated to the reporting unit.

The Company’s impairment analysis involves the use of a blended income and market approach. Significant management judgment is necessary to evaluate the impact of operating and macroeconomic changes on each reporting unit. Critical assumptions include projected revenue growth, fleet count, utilization, gross profit rates, sales, general and administrative ("SG&A") rates, working capital fluctuations, capital expenditures, discount rates, terminal growth rates and price-to-earnings multiples. The Company’s market capitalization is also used to corroborate reporting unit valuations.

Definite-lived intangible assets are amortized over their estimated useful lives and are reviewed for impairment when a triggering event occurs. With the exception of the C&J trade name, these intangibles, along with PP&E, are reviewed for impairment when a triggering event indicates that the asset group may have a net book value in excess of recoverable value. In these cases, the Company performs a recoverability test on its PP&E and definite-lived intangible assets by comparing the estimated future net undiscounted cash flows expected to be generated from the use of these assets to the carrying amount of the assets for recoverability. If the estimated undiscounted cash flows exceed the carrying amount of the assets, an impairment does not exist, and a loss will not be recognized. If the undiscounted cash flows are less than the carrying amount of the assets, the assets are not recoverable and the amount of impairment must be determined by fair valuing the assets. The C&J trade name is a corporate asset and is reviewed for impairment upon the occurrence of a triggering event by comparing the carrying amount of the corporate assets with the remaining cash flows available, after taking into consideration the lower level asset groups that benefit from the C&J trade name.

Deferred Financing Costs. Costs incurred to obtain term debt financing are presented on the balance sheet as a direct deduction from the carrying amount of the term debt, consistent with debt discounts, and accreted over the term of the loan using the effective interest method. Costs incurred to obtain revolver based financing are capitalized and amortized over the term of the loan using the effective interest method.

Revenue Recognition. The Company adopted Accounting Standards Update ("ASU") No. 2014-09, Revenue from Contracts with Customers and its related updates as codified under ASC 606, Revenue from Contracts with Customers ("ASC 606") on January 1, 2018, using the modified retrospective method for all contracts not completed as of the date of adoption. The reported results for the three and six months ended June 30, 2018 reflect the application of ASC 606 guidance while the reported results for the corresponding prior year period were prepared under the previous guidance of ASC No. 605, Revenue Recognition ("ASC 605").

The adoption of ASC 606 represents a change in accounting principle that more closely aligns revenue recognition with the performance of the Company's services and provides financial statement readers with enhanced disclosures. In accordance with ASC 606, revenue is recognized in a manner reflecting the transfer of goods or services to customers based on consideration a company expects to receive. The Company recognizes revenue when it satisfies a performance obligation by transferring control over a product or service to a customer. To achieve this core principle, ASC 606 requires the Company to apply the following five steps: (1) identify the contract with a customer, (2) identify the performance obligations in the contract, (3) determine the transaction price, (4) allocate the transaction price to performance obligations in the contract, and (5)

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C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

recognize revenue when or as the Company satisfies a performance obligation. The five-step model requires management to exercise judgment when evaluating contracts and recognize revenue.

The Company’s services create or enhance a customer controlled asset. The performance obligations of each of the Company’s services lines are primarily satisfied over time. Measurement of the satisfaction of the performance obligations is measured using the output method, which is typically evidenced by a field ticket. A field ticket includes items such as services performed, consumables used, and man hours incurred to complete the job for the customer. Each field ticket is used to invoice customers. Payment terms for invoices issued are in accordance with the master services agreement with each customer, which typically require payment within 30 days of the invoice issuance.

A portion of the Company’s contracts contain variable consideration; however, this variable consideration is typically unknown at the time of contract inception, and is not known until the job is complete, at which time the variability is resolved. Examples of variable consideration include the number of hours that will be incurred and the amount of consumables (such as fluids and proppants) that will be used to complete a job.

In the course of providing services to its customers, the Company may use consumables; for example, in the Company’s fracturing business, sand, guar and chemicals are used in the fracturing service for the customer. ASC 606 requires that goods or services promised to a customer be identified separately when they are distinct within the contract. However, the consumables are used to complete the service for the customer and are not beneficial to the customer on their own. As such, the consumables are not a separate performance obligation, but instead are combined with the other services within the context of the contract and accounted for as a single performance obligation.

Disaggregation of Revenue

The following tables disaggregate revenue by the Company's reportable segments, core service lines and geography (in thousands):



	Three Months Ended June 30, 2018
	Completion Services		WC&I		Well Support Services		Total
Product Service Line
Fracturing	$	288,855	$	—	$	—	$	288,855
Cased-hole Wireline & Pumping	115,377		—		—		115,377
Cementing	—		69,328		—		69,328
Coiled Tubing	—		29,758		—		29,758
Rig Services	—		—		51,716		51,716
Fluids Management	—		—		34,128		34,128
Other	8,663		—		12,696		21,359
	$	412,895	$	99,086	$	98,540	$	610,521
Geography
West Texas	$	170,343	$	56,504	$	26,286	$	253,133
South Texas / South East	135,437		13,034		9,280		157,751
Rockies / Bakken	44,076		5,557		9,402		59,035
California	5,796		—		44,570		50,366
Mid-Con	38,833		12,157		8,278		59,268
North East	16,418		11,834		659		28,911
Other	1,992		—		65		2,057
	$	412,895	$	99,086	$	98,540	$	610,521

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)



	Three Months Ended June 30, 2017
	Completion Services		WC&I		Well Support Services		Total
Product Service Line
Fracturing	$	183,714	$	—	$	—	$	183,714
Cased-hole Wireline & Pumping	76,644		—		—		76,644
Cementing	—		12,432		—		12,432
Coiled Tubing	—		18,577		—		18,577
Rig Services	—		—		54,022		54,022
Fluids Management	—		—		32,141		32,141
Other	2,522		258		9,833		12,613
	$	262,880	$	31,267	$	95,996	$	390,143
Geography
West Texas	$	100,987	$	11,392	$	21,874	$	134,253
South Texas / South East	62,966		9,216		10,886		83,068
Rockies / Bakken	53,628		—		9,893		63,521
California	3,494		—		37,885		41,379
Mid-Con	20,075		3,154		6,794		30,023
North East	20,979		7,505		1,934		30,418
Other	751		—		6,730		7,481
	$	262,880	$	31,267	$	95,996	$	390,143



	Six Months Ended June 30, 2018
	Completion Services		WC&I		Well Support Services		Total
Product Service Line
Fracturing	$	558,346	$	—	$	—	$	558,346
Cased-hole Wireline & Pumping	215,131		—		—		215,131
Cementing	—		130,877		—		130,877
Coiled Tubing	—		55,546		—		55,546
Rig Services	—		—		100,162		100,162
Fluids Management	—		—		65,923		65,923
Other	13,563		80		23,893		37,536
	$	787,040	$	186,503	$	189,978	$	1,163,521
Geography
West Texas	$	349,318	$	105,283	$	50,108	$	504,709
South Texas / South East	234,621		25,717		18,057		278,395
Rockies / Bakken	83,085		10,539		19,335		112,959
California	10,844		—		84,400		95,244
Mid-Con	74,453		22,337		16,107		112,897
North East	31,454		22,627		1,280		55,361
Other	3,265		—		691		3,956
	$	787,040	$	186,503	$	189,978	$	1,163,521

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)



	Six Months Ended June 30, 2017
	Completion Services		WC&I		Well Support Services		Total
Product Service Line
Fracturing	$	314,377	$	—	$	—	$	314,377
Cased-hole Wireline & Pumping	132,909		—		—		132,909
Cementing	—		19,935		—		19,935
Coiled Tubing	—		36,335		—		36,335
Rig Services	—		—		109,567		109,567
Fluids Management	—		—		62,075		62,075
Other	7,403		1,116		20,620		29,139
	$	454,689	$	57,386	$	192,262	$	704,337
Geography
West Texas	$	186,565	$	19,798	$	41,362	$	247,725
South Texas / South East	101,243		19,364		23,287		143,894
Rockies / Bakken	87,597		—		18,873		106,470
California	6,210		—		72,451		78,661
Mid-Con	36,789		5,280		12,946		55,015
North East	34,634		12,944		4,059		51,637
Other	1,651		—		19,284		20,935
	$	454,689	$	57,386	$	192,262	$	704,337

The following is a description of the Company’s core service lines separated by reportable segments from which the Company generates its revenue. For additional detailed information regarding reportable segments, see Note 7 - Segment Information.

Completion Services Segment

Fracturing Services Revenue. Through its fracturing service line, the Company provides fracturing services (i) under term pricing agreements; (ii) on a spot market basis; (iii) under contracts that include dedicated fleet arrangements or; (iv) under term contracts that include "take-or-pay" provisions. Revenue is typically 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 services performed and the consumables (such as fluids and proppants) used during the course of service. The field tickets may also include charges for the personnel on the job, any additional equipment used on the job and other miscellaneous consumables.

Under term pricing agreements, the Company and its customer agree to set pricing for a specified period of time. The agreed-upon pricing is subject to periodic review, as specifically defined in the agreement, and may be adjusted upon the agreement of both parties. These agreements typically do not feature provisions obligating either party to commit to a certain utilization level. Additionally, these agreements typically allow either party to terminate the agreement for its convenience without incurring a termination penalty.

Rates for services performed on a spot market basis are based on an agreed-upon spot market rate for each stage the Company fractures.

Pursuant to dedicated fleet arrangements, customers typically commit to targeted utilization levels based on a specified number of fracturing stages per calendar month or fulfilling the customer's requirements, in either instance at agreed-upon pricing. These agreements typically do not feature obligations to pay for services not used 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 upon the agreement of both parties. These contracts also typically allow for termination for either party's convenience with a brief notice period and typically feature a termination penalty in the event the customer terminates the contract for its convenience.

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C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Under term contracts with “take-or-pay” provisions, the Company’s customers are typically obligated to pay on a monthly basis for a specified quantity of services, whether or not those services are actually utilized. To the extent customers use more than the specified contracted minimums, the Company will charge a pre-agreed amount for the provision of such additional services, which amounts are typically subject to periodic review. In addition, these contracts typically feature a termination penalty in the event the customer terminates the contract for its convenience.

Cased-hole Wireline & Pumping Services Revenue. Through its cased-hole wireline & pumping services business, the Company provides cased-hole wireline, pumping, wireline logging, perforating, well site make-up and pressure testing and other complementary services, typically on a spot market basis. Jobs for these services are typically short-term in nature, lasting anywhere from a few hours to multiple days. The Company typically charges the customer for these services on a per job basis at agreed-upon spot market rates. Revenue is recognized based on a field ticket issued upon the completion of the job.

The Company may enter into dedicated unit arrangements with its cased-hole wireline & pumping customers from time to time. Pursuant to dedicated unit arrangements, customers typically commit to targeted utilization levels based on the Company fulfilling the customer’s requirements for cased-hole wireline & pumping services at agreed-upon pricing. These agreements typically do not feature obligations to pay for services not used 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 upon the agreement of both parties.

Other Completion Services Revenue. The Company generates revenue from its R&T department, which is primarily engaged in the engineering and production of certain parts and components, such as perforating guns and addressable switches, which are used in the completion process. For R&T, the performance obligation is satisfied at a point in time; revenue is recognized upon the completion, delivery and customer acceptance of each order of parts and components.

Well Construction and Intervention Services Segment

Cementing Services Revenue. The Company provides cementing services on a spot market or project basis. Jobs for these services are typically short-term in nature and are generally completed in a few hours. The Company typically charges the customer for these services on a per job basis at agreed-upon spot market rates or agreed-upon job pricing for a particular project. Revenue is recognized, and customers are invoiced upon the completion of each job. 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 consumables used during the course of service.

Coiled Tubing Services Revenue. The Company provides a range of coiled tubing services primarily used for fracturing plug drill-out during completion operations and for well workover and maintenance, primarily on a spot market basis. 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 services performed and the consumables used during the course of service. The field ticket may also include charges for the mobilization and set-up of equipment, the personnel on the job, any additional equipment used on the job, and other miscellaneous consumables. The Company typically charges the customer for the services performed and resources provided on an hourly basis at agreed-upon spot market rates or pursuant to pricing agreements.

Directional Drilling Services Revenue. Through the first quarter of 2018, the Company provided directional drilling services on a spot market basis. Jobs for these services were typically short-term in nature, lasting anywhere from a few days to multiple weeks. The Company typically charged the customer for these services on a per day basis at agreed-upon spot market rates depending on the level of services required and the complexity of the job. Revenue was recognized, and customers were invoiced upon the completion of each job. Once a job had been completed to the customer’s satisfaction, a field ticket was written that included charges for the service performed. During the first quarter of 2018, the Company decided to exit the directional drilling business. Directional drilling operations ceased during the first quarter of 2018.

Well Support Services Segment

Rig Services Revenue. Through its rig service line, the Company provides workover and well servicing rigs that are primarily used for routine repair and maintenance of oil and gas wells, re-drilling operations and plugging and abandonment operations. These services are provided on an hourly basis at prices that approximate spot market rates. Revenue is recognized, and a field ticket is generated upon the earliest of the completion of a job or at the end of each day. A rig services

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

job can last anywhere from a few hours to multiple days depending on the type of work being performed. The field ticket includes the base hourly rate charge and, if applicable, charges for additional personnel or equipment not contemplated in the base hourly rate. The field ticket may also include charges for the mobilization and set-up of equipment.

Fluids Management Services Revenue. Through its fluids management service line, the Company primarily provides storage, transportation and disposal services for fluids used in the drilling, completion and workover of oil and gas wells. Rates for these services vary and can be on a per job, per hour, or per load basis, or on the basis of quantities sold or disposed. Revenue is recognized upon the completion of each job or load, or delivered product, based on a completed field ticket.

Other Special Well Site Services Revenue. Through its other special well site service line, the Company primarily provides fishing, contract labor and tool rental services for completion and workover of oil and gas wells. Rates for these services vary and can be on a per job, per hour or on the basis of rental days per month. Revenue is recognized based on a field ticket issued upon the completion of each job or on a monthly billing for rental services provided.

With respect to its artificial lift applications, the Company generated revenue primarily from the sale of manufactured equipment and products. Revenue was recognized upon the completion, delivery and customer acceptance of each order. During the first quarter of 2018, the Company began to divest this business and has completed the divestiture of substantially all of the assets and inventory associated with the artificial lift business.

Remaining Performance Obligations

The Company invoices its customers for the services provided at contractual rates agreed to in pricing agreements multiplied by the applicable unit of measurement, including volume of consumables used and hours incurred. In accordance with ASC 606-10-55-18, the Company has elected the “Right to Invoice” practical expedient, which allows the Company to invoice its customers in an amount that corresponds directly with the value to the customer of the entity’s performance completed to date. With this election, the Company is not required to disclose information about the variable consideration related to its remaining performance obligations. Because of the short-term nature of the Company’s services, which generally last a few hours to multiple days, the Company does not have any contracts with a duration of longer than one year that require disclosure.

Contract Balances

Accounts receivable as presented on the Company’s consolidated balance sheets represent amounts due from customers for services provided. Bad debt expense of $1.5 million and $2.0 million was included as a component of direct costs on the consolidated statements of operations for the six months ended June 30, 2018 and 2017, respectively.

The Company does not have any contracts in which it performs services to customers and payment for those services are contingent upon a future event (e.g., satisfaction of another performance obligation). As such, there are no contingent revenues or other contract assets recorded in the financial statements.

Significant Judgments

The majority of the Company’s performance obligations are satisfied over time. The Company has determined this best represents the transfer of control over services to the customer as performance by the Company helps to enhance a customer controlled asset (e.g., unplugging a well, enabling a well to produce oil or natural gas). Revenue is recognized over time as the Company satisfies its performance obligations. Field tickets are issued periodically throughout and upon completion of each job to evidence the services performed for each job and support the use of the output method.

"Take-or-pay" provisions as part of fracturing contracts are considered stand ready performance obligations. The Company recognizes revenue for "take-or-pay" revenues using a time-based measure of progress, as the Company cannot reasonably estimate if and when the customer will require the use of the Company’s fleet to provide the fracturing services; likewise, the customer can benefit when a well needs fracturing services from the fleet which is standing by to provide such services.

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C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For R&T sales, the Company recognizes revenue at the point in time in which the products are delivered to and accepted by the customer because the customer obtains control along with the risks and rewards of ownership of the products at such time. Once delivered, the Company has the right to invoice the customer.

The Company does not have any significant contract costs to obtain or fulfill contracts with customers; as such, no amounts are recognized on the consolidated balance sheet.

Impact of Adoption on the Financial Statements

The Company adopted ASC 606 on January 1, 2018 using the modified retrospective method for all contracts not completed as of such date. Under this method, the comparative financial statements for the periods presented prior to the adoption date are not adjusted and continue to be reported under the revenue recognition guidance of ASC 605. After reviewing the Company's contracts and the revenue recognition guidance under ASC 606 there are no material differences between revenue recognition under ASC 605 and ASC 606. As a result, there is not a cumulative effect adjustment recorded to beginning retained earnings or recognition of any contract assets or liabilities upon adoption of ASC 606.

Share-Based Compensation. The Company’s share-based compensation plan provides the ability to grant equity awards to the Company’s employees, consultants and non-employee directors. As of June 30, 2018, only nonqualified stock options, restricted shares and performance awards had been granted under such plans. The fair value of restricted stock grants is based on the closing price of C&J’s common stock on the grant date. The Company values option grants based on the grant date fair value using the Black-Scholes option-pricing model, and the Company values equity awards with market conditions based on the grant date fair value using a Monte Carlo simulation, both of which require the use of subjective assumptions. The Company recognizes share-based compensation expense on a straight-line basis over the requisite service period for the entire award. Further information regarding the Company’s share-based compensation arrangements and the related accounting treatment can be found in Note 5 - Share-Based Compensation.

Fair Value of Financial Instruments. The Company’s financial instruments consist of cash and cash equivalents, accounts receivable and accounts payable. The recorded values of cash and cash equivalents, accounts receivable and accounts payable approximate their fair values given the short-term nature of these instruments.

Equity Method Investments. The Company has investments in joint ventures which are accounted for under the equity method of accounting as the Company has the ability to exercise significant influence over operating and financial policies of the joint venture. Judgment regarding the level of influence over each equity method investment includes considering key factors such as ownership interest, representation on the board of directors, participation in policy-making decisions and material intercompany transactions. Under the equity method, original investments are recorded at cost and adjusted by the Company’s share of undistributed earnings and losses of these investments. The Company eliminates all significant intercompany transactions, including the intercompany portion of transactions with equity method investees, from the consolidated financial results.

Income Taxes. The Company is subject to income and other similar taxes in all areas in which they operate. When recording income tax expense, certain estimates are required because: (a) income tax returns are generally filed months after the close of the Company's annual accounting period; (b) tax returns are subject to audit by taxing authorities and audits can often take years to complete and settle; and (c) future events often impact the timing of when the Company recognizes income tax expenses and benefits.

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 basis. 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 due to 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 cumulative losses in recent years, 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 a portion or all of the deferred tax assets will not be realized.

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C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

The Company has federal, state and international net operating losses ("NOLs") carried forward from prior years that will expire in the years 2021 through 2037. After considering the scheduled reversal of deferred tax liabilities, projected future taxable income, the potential limitation on use of NOLs under Section 382 of the Internal Revenue Code of 1986, as amended (the "Code") and tax planning strategies, the Company established a valuation allowance due to the uncertainty regarding the ultimate realization of the deferred tax assets associated with its NOL carryforwards.

As a result of the Chapter 11 Proceeding, on the Plan Effective Date, the Company believes it experienced an ownership change for purposes of Section 382 of the Code because of its Restructuring Plan and that consequently its pre-change NOLs are subject to an annual limitation (See Note 2 - Chapter 11 Proceeding and Emergence for additional information, including definitions of capitalized defined terms, about the Chapter 11 Proceeding and emergence from the Chapter 11 Proceeding). The ownership change and resulting annual limitation on use of NOLs are not expected to result in the expiration of the Company's NOL carryforwards if it is able to generate sufficient future taxable income within the carryforward periods. However, the limitation on the amount of NOLs available to offset taxable income in a specific year may result in the payment of income taxes before all NOLs have been utilized. Additionally, a subsequent ownership change may result in further limitation on the ability to utilize existing NOLs and other tax attributes, which could cause our pre-change NOL carryforwards to expire unused.

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 50.0% likely of being realized upon ultimate settlement with a taxing authority. Previously recognized uncertain tax positions are reversed in the first period in which it is 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. As of June 30, 2018, the Company has no uncertain tax positions.

Earnings (Loss) Per Share. Basic earnings per share is based on the weighted average number of common shares (“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. The following is a reconciliation of the components of the basic and diluted earnings (loss) per share calculations for the applicable periods:



	Three Months Ended June 30, 2018		Three Months Ended June 30, 2017
	(In thousands, except per share amounts)
Numerator:
Net income (loss) attributed to common stockholders	$	28,496	$	(12,721	)
Denominator:
Weighted average common shares outstanding	67,268		62,232
Effect of potentially dilutive common shares:
Stock options	—		—
Warrants	—		—
Restricted shares	—		—
Weighted average common shares outstanding and assumed conversions	67,268		62,232
Income (loss) per common share:
Basic	$	0.42	$	(0.20	)
Diluted	$	0.42	$	(0.20	)

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C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)



	Successor					Predecessor
	Six Months Ended June 30, 2018		Six Months Ended June 30, 2017			On January 1, 2017
	(In thousands, except per share amounts)					(In thousands, except per share amounts)
Numerator:
Net income (loss) attributed to common stockholders	$	49,090	$	(45,022	)	$	298,582
Denominator:
Weighted average common shares outstanding	67,227		58,913			118,633
Effect of potentially dilutive common shares:
Stock options	—		—			—
Warrants	38		—			—
Restricted shares	2		—			—
Weighted average common shares outstanding and assumed conversions	67,267		58,913			118,633
Income (loss) per common share:
Basic	$	0.73	$	(0.76	)	$	2.52
Diluted	$	0.73	$	(0.76	)	$	2.52

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



	Three Months Ended June 30, 2018	Three Months Ended June 30, 2017
	(In thousands)
Basic earnings (loss) per share:
Restricted shares	1,130	572
Diluted earnings (loss) per share:
Anti-dilutive stock options	351	256
Anti-dilutive warrants	3,528	—
Anti-dilutive restricted shares	1,104	556
Potentially dilutive securities excluded as anti-dilutive	4,983	812



	Successor		Predecessor
	Six Months Ended June 30, 2018	Six Months Ended June 30, 2017	On January 1, 2017
	(In thousands)		(In thousands)
Basic earnings (loss) per share:
Restricted shares	1,205	436	898
Diluted earnings (loss) per share:
Anti-dilutive stock options	351	205	4,416
Anti-dilutive warrants	1,764	—	—
Anti-dilutive restricted shares	1,188	427	898
Potentially dilutive securities excluded as anti-dilutive	3,303	632	5,314

Recent Accounting Pronouncements. In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) ("ASU 2016-02"). ASU No. 2016-02 seeks to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and by disclosing key information about leasing arrangements. Unlike current U.S. GAAP, which requires only capital leases to be recognized on the balance sheet, ASU No. 2016-02 will require both operating and finance leases to be recognized on the balance sheet. Additionally, the new guidance will require disclosures

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C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

to help investors and other financial statement users better understand the amount, timing, and uncertainty of cash flows arising from leases, including qualitative and quantitative requirements. The amendments in ASU No. 2016-02 are effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years, and early application is permitted. The Company will adopt this new accounting standard on January 1, 2019. The Company is currently determining the impacts of the new standard on its consolidated financial statements. The approach includes performing a detailed review of its lease portfolio by evaluating its population of leased assets and designing and implementing new processes and controls.

In June 2016, the FASB issued ASU No. 2016-13, Financial Instruments-Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments (“ASU 2016-13”), which amends U.S. GAAP by introducing a new impairment model for financial instruments that is based on expected credit losses rather than incurred credit losses. The new impairment model applies to most financial assets, including trade accounts receivable. The amendments in ASU 2016-13 are effective for interim and annual reporting periods beginning after December 15, 2019, although it may be adopted one year earlier, and requires a modified retrospective transition approach. The Company is currently evaluating the impact this standard will have on its consolidated financial statements.

In October 2016, the FASB issued ASU No. 2016-16, Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other Than Inventory ("ASU 2016-16"), which requires an entity to recognize the income tax consequences of an intra-entity asset transfer, other than an intra-entity asset transfer of inventory, when the transfer occurs. The ASU is effective for the interim and annual reporting periods beginning after December 15, 2017, including interim periods within those fiscal years, and early application is permitted. The Company adopted this new accounting standard on January 1, 2018. The Company recognized a cumulative effect adjustment as a reduction to retained earnings of $13.2 million which occurred as a result of the Company's adoption of ASU 2016-16.

In January 2017, the FASB issued ASU No. 2017-04, Intangibles-Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment ("ASU 2017-04"), which establishes a one-step process for testing goodwill for a drop in value. This ASU is effective for the interim and annual reporting periods beginning after December 15, 2019 and early adoption is permitted. The Company early adopted this new accounting standard on January 1, 2018, and there was no impact on its consolidated financial statements.

In February 2018, the FASB issued ASU No. 2018-02, Income Statement - Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income ("ASU 2018-02"), which allows for a reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the Tax Cuts and Jobs Act and requires certain disclosures about stranded tax effects. This ASU is effective for the interim and annual reporting periods beginning after December 15, 2019, and early adoption is permitted. The Company is currently evaluating the impact of this standard on its consolidated financial statements.

In March 2018, the FASB issued ASU No. 2018-05, Income Taxes (Topic 740): Amendments to SEC Paragraphs Pursuant to SEC Staff Accounting Bulletin No. 118, ("ASU 2018-05"), which provides guidance on accounting for the tax effects of the Tax Cuts and Jobs Act (the "Tax Act") pursuant to Staff Accounting Bulletin No. 18, which allows companies to complete the accounting under ASC 740 within a one-year measurement period from the Tax Act enactment date. This standard is effective upon issuance. The Company is currently within the one-year measurement period and is in the process of accounting for the tax effects of the Tax Act.

In June 2018, the FASB issued ASU No. 2018-07, Compensation-Stock Compensation (Topic 718): Improvements to Nonemployee Share-Based Payment Accounting, ("ASU 2018-07"), which expands the scope of Topic 718 to include all share-based payment transactions for acquiring goods and services from nonemployees. This ASU is effective for the interim and annual reporting periods beginning after December 15, 2018, and early adoption is permitted. The Company is currently evaluating the impact of this standard on its consolidated financial statements.

Note 2 - Chapter 11 Proceeding and Emergence

On July 8, 2016, C&J Energy Services Ltd., a Bermuda corporation (the “Predecessor”) and certain of its direct and indirect subsidiaries (collectively, the “Debtors”), including C&J Corporate Services (Bermuda) Ltd. (together with the Predecessor, the “Bermudian Entities”), C&J Energy Production Services-Canada Ltd. and Mobile Data Technologies Ltd. (together, the “Canadian Entities”), entered into a Restructuring Support and Lock-Up Agreement (the “Restructuring Support Agreement”), with certain lenders (the “Supporting Lenders”) holding approximately 90.0% of the secured claims and interests arising under the Credit Agreement, dated as of March 24, 2015 (as amended and otherwise modified, the “Original Credit

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C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Agreement”). The Restructuring Support Agreement contemplated the implementation of a financial restructuring of the Company, including the elimination of all amounts owed under the Original Credit Agreement through a complete debt-to-equity conversion and a re-investment in the Company through an equity rights offering. This financial restructuring was effectuated through the Restructuring Plan under Chapter 11 of the Bankruptcy Code.

To implement the Restructuring Support Agreement, on July 20, 2016 (the “Petition Date”), the Debtors filed voluntary petitions for reorganization (the “Bankruptcy Petitions”) seeking relief under the provisions of Chapter 11 of the Bankruptcy Code with the United States Bankruptcy Court in the Southern District of Texas, Houston Division (the “Bankruptcy Court”), and also commenced ancillary proceedings in Canada on behalf of the Canadian Entities and a provisional liquidation proceeding in Bermuda on behalf of the Bermudian Entities (collectively, the “Chapter 11 Proceeding”). The Chapter 11 Proceeding was being administered under the caption “In re: CJ Holding Co., et al., Case No. 16-33590”. Throughout the Chapter 11 Proceeding, the Debtors continued operations and management of their assets in the ordinary course as debtors-in-possession under the jurisdiction of the Bankruptcy Court in accordance with the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court.

In accordance with the Restructuring Support Agreement, the Debtors filed the plan of reorganization (the " Restructuring Plan") and related disclosure statement (the “Disclosure Statement”) with the Bankruptcy Court on August 19, 2016, with a first amendment to the Restructuring Plan filed on September 28, 2016 and a second amendment filed on November 3, 2016. On November 4, 2016, the Bankruptcy Court approved the Disclosure Statement, finding that the Disclosure Statement contained adequate information as required by the Bankruptcy Code. The Debtors then launched a solicitation of acceptances of the Restructuring Plan, as required by the Bankruptcy Code. On December 16, 2016, an order confirming the Restructuring Plan was entered by the Bankruptcy Court. On January 6, 2017 (the "Plan Effective Date"), the Debtors substantially consummated the Restructuring Plan and emerged from the Chapter 11 Proceeding. As part of the transactions undertaken pursuant to the Restructuring Plan, as of the Plan Effective Date, the Successor was formed, the Predecessor's equity was canceled, the Predecessor transferred all of its assets and operations to the Successor and the Predecessor was subsequently dissolved. As a result, the Successor became the successor issuer to the Predecessor. For additional information regarding the Chapter 11 Proceeding and Emergence, please read the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2017.

Reorganization Items

The Company classifies all income, expenses, gains or losses that were incurred or realized as a result of the Chapter 11 Proceeding as reorganization items in its consolidated statements of operations. In addition, the Company reports professional fees and related costs associated with and incurred during the Chapter 11 Proceeding as reorganization items. The components of reorganization items are as follows (in thousands):



	On January 1, 2017
Gain on settlement of liabilities subject to compromise	$	666,399
Net loss on fresh start fair value adjustments	(358,557		)
Professional fees	(13,435		)
Vendor claims adjustment	(438		)
Total reorganization items	$	293,969

While the Company’s emergence from bankruptcy is complete, certain administrative activities will continue under the authority of the Bankruptcy Court through at least the remainder of 2018.

Note 3 - Debt

Credit Facility

The Company and certain of its subsidiaries (the “Borrowers”) entered into an asset-based revolving credit agreement with, among others, JPMorgan Chase Bank, N.A., as administrative agent (the “Agent”), on May 1, 2018 (the “Credit Facility”).

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C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

accounts receivable, inventory and restricted cash, subject to eligibility criteria and customary reserves which may be modified in the Agent’s permitted discretion.

The Credit Facility also provides for the issuance of letters of credit, which would further reduce borrowing capacity thereunder. The maturity date of the Credit Facility is May 1, 2023.

If at any time the amount of loans and other extensions of credit outstanding under the Credit Facility exceed the borrowing base, the Borrowers may be required, among other things, to prepay outstanding loans immediately.

The Borrowers’ obligations under the Credit Facility are secured by liens on a substantial portion of the Borrowers’ personal property, subject to certain exclusions and limitations. Upon the occurrence of certain events, additional collateral, including a portion of the Borrowers’ real properties, may also be required to be pledged. Each of the Borrowers is jointly and severally liable for the obligations of the other Borrowers under the Credit Facility.

At the Borrowers’ election, interest on borrowings under the Credit Facility will be determined by reference to either LIBOR plus an applicable margin of between 1.5% and 2.0% or an “alternate base rate” plus an applicable margin of between 0.5% and 1.0%, in each case based on the Company’s total leverage ratio. Interest will be payable quarterly for loans bearing interest based on the alternative base rate and on the last day of the interest period applicable to LIBOR-based loans and, in the case of an interest period longer than three months, quarterly, upon any prepayment and at final maturity. The Borrowers will also be required to pay a fee on the unused portion of the Credit Facility equal to (i) 0.5% per annum if average utilization is less than or equal to 25% or (ii) 0.375% per annum if average utilization is greater than 25%, in each case payable quarterly in arrears to the Agent.

The Credit Facility contains covenants that limit the Borrowers’ ability to incur additional indebtedness, grant liens, make loans, make acquisitions or investments, make distributions, merge into or consolidate with other persons, or engage in certain asset dispositions.

The Credit Facility also contains a financial covenant which requires the Company to maintain a monthly minimum fixed charge coverage ratio of 1.0:1.0 upon the occurrence of an event of default or on any date upon which the excess availability is less than the greater of (x) 12.5% of the lesser of the Loan Cap and (y) $30.0 million. The fixed charge coverage ratio is generally defined in the Credit Facility as the ratio of (i) EBITDA minus certain capital expenditures and cash taxes paid to (ii) the sum of cash interest expenses, scheduled principal payments on borrowed money and certain distributions.

As of June 30, 2018, the Company was in compliance with all financial covenants of the Credit Facility.

Prior Credit Facility

On January 6, 2017, in connection with the emergence from bankruptcy, the Company entered into a revolving credit and security agreement with PNC Bank, National Association, as administrative agent (the “Prior Agent”), which was subsequently amended and restated on May 4, 2017 (the “Prior Credit Facility”). The Prior Credit Facility was canceled and discharged on May 1, 2018.

The Prior Credit Facility allowed the Company and certain of its subsidiaries (the “Prior Borrowers”), to incur revolving loans in an aggregate amount up to the lesser of $200.0 million and a borrowing base, which borrowing base was based upon the value of the Prior Borrowers’ accounts receivable and inventory, subject to eligibility criteria and customary reserves which may have been modified in the Agent’s permitted discretion. The Prior Credit Facility also provided for the issuance of letters of credit, which would further reduce borrowing capacity thereunder. The maturity date of the Prior Credit Facility was May 4, 2022.

If at any time the amount of loans and other extensions of credit outstanding under the Prior Credit Facility exceeded the borrowing base, the Prior Borrowers may have been required, among other things, to prepay outstanding loans immediately.

The Prior Borrowers’ obligations under the Prior Credit Facility were secured by liens on a substantial portion of the Prior Borrowers’ personal property, subject to certain exclusions and limitations. Upon the occurrence of certain events, additional collateral, including a portion of the Prior Borrowers’ real properties, may also have been required to be pledged.

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C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Each of the Prior Borrowers was jointly and severally liable for the obligations of the other Prior Borrowers under the Prior Credit Facility.

At the Prior Borrowers’ election, interest on borrowings under the Prior Credit Facility would have been determined by reference to either LIBOR plus an applicable margin of 2.0% or an “alternate base rate” plus an applicable margin of 1.0%. Beginning after the fiscal month ending on or about September 30, 2017, these margins were subject to a monthly step-up of 0.25% in the event that average excess availability under the Prior Credit Facility was less than 37.5% of the total commitment, and a monthly step-down of 0.25% in the event that average excess availability under the Prior Credit Facility was equal to or greater than 62.5% of the total commitment. Interest was payable quarterly for loans bearing interest based on the alternative base rate and on the last day of the interest period applicable to LIBOR-based loans. The Prior Borrowers were also required to pay a fee on the unused portion of the Prior Credit Facility equal to (i) 0.75% in the event that utilization was less than 25% of the total commitment, (ii) 0.50% in the event utilization was equal to or greater than 25% of the total commitment but less than 50% of the total commitment and (iii) 0.375% in the event that utilization was equal to or greater than 50% of the total commitment.

The Prior Credit Facility contained covenants that limited the Prior Borrowers’ ability to incur additional indebtedness, grant liens, make loans or investments, make distributions, merge into or consolidate with other persons, make capital expenditures or engage in certain asset dispositions including a sale of all or substantially all of the Company’s assets.

The Prior Credit Facility also contained a financial covenant that required the Company to maintain a monthly minimum fixed charge coverage ratio of 1.0:1.0 if, as of any month-end, liquidity was less than $40.0 million.

The fixed charge coverage ratio was generally defined in the Prior Credit Facility as the ratio of (i) EBITDA minus certain capital expenditures and cash taxes paid to (ii) the sum of cash interest expenses, scheduled principal payments on borrowed money and certain distributions.

In connection with the cancellation and discharge of the Prior Credit Facility, the Company accelerated the amortization of $1.5 million in deferred financing costs.

Note 4 - Goodwill and Other Intangible Assets

On November 30, 2017, the Company acquired all of the outstanding equity interests of O-Tex Holdings, Inc., and its operating subsidiaries (“O-Tex”). See Note 8 - Acquisitions for further discussion on the O-Tex acquisition. As of June 30, 2018, all of the goodwill reported on the Company's consolidated balance sheet is related to the O-Tex acquisition, which was allocated to the Company's WC&I reporting unit.

The changes in the carrying amount of goodwill for the six months ended June 30, 2018 are as follows (in thousands):



	WC&I
December 31, 2017	147,515
Purchase price adjustment	(1,500	)
June 30, 2018	146,015

Definite-Lived Intangible Assets

The Company reviews definite-lived intangible assets, along with PP&E, for impairment when a triggering event indicates that the asset may have a net book value in excess of recoverable value.

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C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

The change in the carrying amounts of other intangible assets as of the June 30, 2018 is presented as follows (in thousands):



	Amortization Period	December 31, 2017			Amortization Expense			June 30, 2018
Customer relationships	8-15 years	$	58,100		$	—		$	58,100
Trade name	10-15 years	68,300			—			68,300
Non-compete	4-5 years	1,600			—			1,600
		128,000			—			128,000
Less: accumulated amortization		(4,163		)	(4,392		)	(8,555		)
Intangible assets, net		$	123,837		$	(4,392	)	$	119,445

Note 5 - Share-Based Compensation

Pursuant to the Restructuring Plan, the Company adopted the C&J Energy Services, Inc. 2017 Management Incentive Plan (as amended from time to time, the “MIP”) as of the Plan Effective Date.

The MIP provides for the grant of share-based awards to the Company’s employees, consultants and non-employee directors. The following types of awards are available for issuance under the MIP: incentive stock options and nonqualified stock options, share appreciation rights, restricted shares, restricted share units, dividend equivalent rights, performance awards, share awards, other share-based awards and substitute awards. As of June 30, 2018, only nonqualified stock options, restricted shares and performance awards have been awarded under the MIP.

A total of approximately 8.0 million shares of common stock were originally authorized and approved for issuance under the MIP. The number of shares of common stock available for issuance under the MIP is subject to adjustment in the event of a reclassification, recapitalization, merger, consolidation, reorganization, spin-off, split-up, issuance of warrants, rights or debentures, share dividend, share split or reverse share split, cash dividend, property dividend, combination or exchange of shares, repurchase of shares, change in corporate structure or any similar corporate event or transaction. The number of shares of common stock available for issuance may also increase due to the termination of an award granted under the MIP or by expiration, forfeiture, cancellation or otherwise without the issuance of the common stock.

Stock Options

The fair value of each option award granted under the MIP is estimated on the date of grant using the Black-Scholes option-pricing model. Determination of the fair value was a matter of judgment and often involved the use of significant estimates and assumptions. Additionally, due to the Company’s lack of historical volume of option activity, the expected term of options granted was derived using the “plain vanilla” method. Expected volatilities were 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. During the year ended December 31, 2017, approximately 0.4 million nonqualified stock options were granted under the MIP to certain of the Company's executive officers at a fair market value ranging from $16.55 to $22.19 per nonqualified stock option. Stock options granted during the first quarter of 2017 will expire on the tenth anniversary of the grant date and will vest over three years of continuous service from the grant date, with 34% vesting immediately upon the grant date, and 22% on each of the first, second and third anniversaries of the grant date. Stock options granted during the fourth quarter of 2017 will expire on the tenth anniversary of the grant date and will vest over three years of continuous service from the grant date, with one-third vesting on each of the first, second and third anniversaries of the grant date. During the six months ended June 30, 2018, no stock options were granted by the Company.

As of June 30, 2018, the Company had approximately 0.4 million options outstanding to employees, including 0.2 million unvested options. The Company had approximately $3.0 million of share-based compensation remaining to be expensed over a weighted average remaining service period of 2.0 years.

-22-

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

The following table includes the assumptions used in determining the fair value of option awards granted during the year ended December 31, 2017.



Expected volatility		50.1% - 53.2%
Expected dividends		None
Exercise price		$30.83 - $42.65
Expected term (in years)		5.7 - 6.0
Risk-free rate		2.03% - 2.24%

Restricted Stock

The value of the Company’s outstanding restricted stock is based on the closing price of the Company’s common stock on the NYSE on the date of grant. During year ended December 31, 2017, approximately 1.7 million shares of restricted stock were granted to employees and non-employee directors under the MIP, at fair market values ranging from $31.52 to $44.90 per share of restricted stock. Restricted stock awards granted to employees during the first quarter of 2017 will vest over three years of continuous service from the grant date, with 34% having vested immediately upon the grant date, and 22% on each of the first, second and third anniversaries of the grant date. Restricted stock awards granted to non-employee directors will vest in full on the first anniversary of the date of grant, subject to each director's continued service. Restricted stock awards granted to employees during the fourth quarter of 2017 will vest over three years of continuous service from the grant date, with one-third vesting on each of the first, second and third anniversaries. During the six months ended June 30, 2018, no restricted shares were granted by the Company.

To the extent permitted by law, the recipient of an award of restricted stock will generally have all of the rights of a stockholder with respect to the underlying common stock, including the right to vote the common stock and to receive all dividends or other distributions made with respect to the common stock. Dividends on restricted stock will be deferred until the lapsing of the restrictions imposed on the stock and will be held by the Company for the account of the recipient (either in cash or to be reinvested in restricted stock) until such time. Payment of the deferred dividends and accrued interest, if any, shall be made upon the lapsing of restrictions on the restricted stock, and any dividends deferred in respect of any restricted stock shall be forfeited upon the forfeiture of such restricted stock. As of June 30, 2018, the Company had not issued any dividends.

As of June 30, 2018, the Company had approximately 1.0 million shares of restricted stock outstanding to employees and non-employee directors. The Company had $29.2 million of share-based compensation remaining to be expensed over a weighted average remaining service period of 2.1 years.

Performance Stock

During the fourth quarter of 2017, the Company granted approximately 0.1 million shares of performance stock under the MIP to certain of the Company's executive officers at a fair market value of approximately $37.20 per share of restricted stock. The performance award cliff vests at the end of a three year performance period, and the participants may earn between 0% and 200% of the target number of the shares granted based on actual stock price performance upon comparison to a peer group. The vesting of these awards is subject to the employee's continued employment. The Company values equity awards with market conditions at the grant date using a Monte Carlo simulation model which simulates many possible future outcomes. During the six months ended June 30, 2018, no performance stock was granted by the Company.

As of June 30, 2018, the Company had approximately 0.1 million shares of performance stock outstanding. The Company had $2.6 million of share-based compensation remaining to be expensed over a weighted average remaining service period of 2.5 years.

The following table presents the assumptions used in determining the fair value of the performance stock granted during the fourth quarter of 2017.



Expected volatility, including peer group		30.8% - 81.6%
Expected dividends		None
30 calendar day volume weighted average stock price, including peer group		$2.13 - $133.20
Expected term (in years)		3.0
Risk-free rate		1.94% - 1.95%

-23-

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 6 - Commitments and Contingencies

Environmental Regulations & Liabilities

The Company is subject to various federal, state and local environmental laws and regulations that establish standards and requirements for the protection of the environment. The Company continues to monitor the status of these laws and regulations. However, the Company cannot predict the future impact of such standards and requirements on its business, which are subject to change and can have retroactive effectiveness.

Currently, the Company has not been fined, cited or notified of any environmental violations or liabilities that would have a material adverse effect upon its consolidated financial position, liquidity or capital resources. However, management does recognize that by the very nature of its business, material costs could be incurred in the near term to maintain compliance. The amount of such future expenditures is not determinable due to several factors, including the unknown magnitude of possible regulation or liabilities, the unknown timing and extent of the corrective actions which may be required, the determination of the Company’s liability in proportion to other responsible parties and the extent to which such expenditures are recoverable from insurance or indemnification.

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 difficult to determine or otherwise predict with any certainty 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 on the Company’s consolidated financial position, results of operations or liquidity.

Self-Insured Risk Accruals

The Company maintains insurance policies for workers’ compensation, automobile liability, general liability, environmental liability, and property damage relating to catastrophic events, together with excess loss liability coverage. These insurance policies carry self-insured retention limits or deductibles on a per occurrence basis. The Company has deductibles per occurrence for: (i) workers’ compensation of $1,000,000; (ii) automobile liability claims of $1,000,000; (iii) general liability claims, including sudden and accidental pollution claims, of $250,000, plus an additional annual aggregate deductible of $250,000; (iv) environmental liability claims of $500,000; and (v) property damage for catastrophic events of $50,000. The excess loss liability coverage is subject to an annual aggregate self-insured retention of $5,000,000.

Additionally, under the terms of the Separation Agreement, dated as of February 12, 2015, by and between the Predecessor and Nabors Industries, Ltd. (“Nabors”), relating to a transformative transaction between the Predecessor and Nabors (the “Nabors Merger”), with the exception of certain liabilities for which Nabors has agreed to indemnify the Predecessor, the Predecessor assumed, among other liabilities, all liabilities of the completion and production services business (the “C&P Business”) to the extent arising out of or resulting from the operation of the C&P Business at any time before, at or after the closing of the Nabors Merger, including liability for death, personal injury and property damage resulting from or caused by the assets, products and services of the C&P Business. Any liability relating to or resulting from any claim or litigation asserted after the closing of the Nabors Merger, but where the underlying cause of action arose prior to that time, would not be covered by the Company’s insurance policies.

Note 7 - Segment Information

In accordance with ASC No. 280 - Segment Reporting, the Company routinely evaluates whether its separate operating and reportable segments have changed. This determination is made based on the following factors: (1) the Company’s chief operating decision maker (“CODM”) is currently managing each operating 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 operating segment is available.

Prior to and as of the year ended December 31, 2017, the Company’s reportable segments were: (i) Completion Services and (ii) Well Support Services. Due to the significant expansion of C&J's cementing business, during the first quarter

-24-

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

of 2018 the CODM revised the approach in which performance evaluation and resource allocation decisions are made. Discrete financial information was created to provide the segment information necessary for the CODM to manage the Company under the revised operating segment structure. As a result of this change in operating segments, the Company revised its reportable segments in the first quarter of 2018. The Company's operating and reportable segments are now: (i) Completion Services, (ii) WC&I and (iii) Well Support Services. This segment structure reflects the financial information and reports used by the Company’s management, including its CODM, to make decisions regarding the Company’s business, including performance evaluation and resource allocation decisions. As a result of the revised reportable segment structure, the Company has restated the corresponding segment information for all periods presented.

The following is a brief description of the Company's reportable segments as of June 30, 2018:

Completion Services

The Company’s Completion Services segment consisted of the following businesses and service lines: (1) fracturing services; (2) cased-hole wireline and pumping services; and (3) completion support services, which includes logistics services and the Company's R&T department.

Well Construction and Intervention Services

The Company’s WC&I segment consisted of the following businesses and service lines: (1) cementing services; (2) coiled tubing services and (3) directional drilling services. During the first quarter of 2018, the Company exited its directional drilling business.

Well Support Services

The Company’s Well Support Services segment consisted of the following businesses and service lines: (1) rig services; (2) fluids management services; and (3) special services, which included plug and abandonment, artificial lift applications and other specialty well site services.

-25-

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

The following table sets forth certain financial information with respect to the Company’s reportable segments.



	Completion Services		WC&I			Well Support Services			Corporate / Elimination			Total
Three months ended June 30, 2018
Revenue from external customers	$	412,895	$	99,086		$	98,540		$	—		$	610,521
Inter-segment revenues	134		—			44			(178		)	—
Depreciation and amortization	29,048		9,831			13,199			2,309			54,387
Operating income (loss)	55,626		8,498			(2,709		)	(30,521		)	30,894
Net income (loss)	54,371		8,725			(2,830		)	(31,770		)	28,496
Adjusted EBITDA	83,252		19,632			10,933			(26,041		)	87,776
Capital expenditures	79,663		11,234			988			877			92,762
Six months ended June 30, 2018
Revenue from external customers	$	787,040	$	186,503		$	189,978		$	—		$	1,163,521
Inter-segment revenues	194		—			149			(343		)	—
Depreciation and amortization	51,687		19,763			25,250			4,030			100,730
Operating income (loss)	113,934		13,955			(11,251		)	(65,402		)	51,236
Net income (loss)	112,748		14,177			(11,189		)	(66,646		)	49,090
Adjusted EBITDA	164,150		35,630			16,040			(54,358		)	161,462
Capital expenditures	136,788		14,876			3,194			932			155,790
As of June 30, 2018
Total assets	$	847,152	$	400,091		$	260,733		$	174,734		$	1,682,710
Goodwill	—		146,015			—			—			146,015
Three months ended June 30, 2017
Revenue from external customers	$	262,880	$	31,267		$	95,996		$	—		$	390,143
Inter-segment revenues	746		59			256			(1,061		)	—
Depreciation and amortization	16,274		2,707			12,035			1,817			32,833
Operating income (loss)	28,936		448			(7,608		)	(35,020		)	(13,244		)
Net income (loss)	26,461		448			(7,541		)	(32,089		)	(12,721		)
Adjusted EBITDA	45,114		2,667			1,927			(24,598		)	25,110
Capital expenditures	53,792		2,868			3,750			552			60,962
Six months ended June 30, 2017
Revenue from external customers	$	454,689	$	57,386		$	192,262		$	—		$	704,337
Inter-segment revenues	1,025		59			297			(1,381		)	—
Depreciation and amortization	31,698		5,396			23,750			3,595			64,439
Operating income (loss)	40,280		(87		)	(15,550		)	(74,295		)	(49,652		)
Net income (loss)	37,280		(87		)	(13,737		)	(68,478		)	(45,022		)
Adjusted EBITDA	66,820		3,703			5,751			(46,580		)	29,694
Capital expenditures	60,951		3,143			7,771			682			72,547
As of June 30, 2017
Total assets	$	575,267	$	81,773		$	302,639		$	377,168		$	1,336,847

Management evaluates reportable segment performance and allocates resources based on total earnings (loss) before net interest expense, income taxes, depreciation and amortization, other income (expense), net gain or (loss) on disposal of assets, acquisition-related costs, and non-routine items (“Adjusted EBITDA”), because Adjusted EBITDA is considered an important measure of each reportable segment’s performance. In addition, management believes that the disclosure of Adjusted EBITDA as a measure of each reportable 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

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C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

compensate for the limitations in utilizing Adjusted EBITDA as an operating measure, management also uses U.S. GAAP measures of performance, including operating income (loss) and net income (loss), to evaluate performance, but only with respect to the Company as a whole and not on a reportable segment basis.

As required under Item 10(e) of Regulation S-K of the Exchange Act, included below is a reconciliation of Adjusted EBITDA, a non-GAAP financial measure, from net income (loss), which is the nearest comparable U.S. GAAP financial measure (in thousands) on a consolidated basis for the three and six months ended June 30, 2018 and 2017.



	Three Months Ended June 30, 2018			Three Months Ended June 30, 2017
Net income (loss)	$	28,496		$	(12,721	)
Interest expense, net	2,185			414
Income tax benefit	(893		)	(2,393		)
Depreciation and amortization	54,387			32,833
Other (income) expense, net	1,106			1,456
(Gain) loss on disposal of assets	49			(3,136		)
Acquisition-related and other transaction costs	243			298
Severance and business divestiture costs	40			513
Restructuring costs	2,163			7,846
Adjusted EBITDA	$	87,776		$	25,110



	Six Months Ended June 30, 2018			Six Months Ended June 30, 2017
Net income (loss)	$	49,090		$	(45,022	)
Interest expense, net	2,613			1,105
Income tax benefit	(953		)	(5,629		)
Depreciation and amortization	100,730			64,439
Other (income) expense, net	486			(106		)
Gain on disposal of assets	(440		)	(9,192		)
Acquisition-related and other transaction costs	970			298
Severance and business divestiture costs	6,180			513
Restructuring costs	2,786			7,630
Share-based compensation expense acceleration	—			15,658
Adjusted EBITDA	$	161,462		$	29,694

Note 8 - Acquisitions

Acquisition of O-Tex

On November 30, 2017, the Company acquired all of the outstanding equity interest of O-Tex for approximately $271.9 million, consisting of cash of approximately $132.5 million and 4.42 million shares of the Company's common stock with a fair value of $138.2 million. The Company also acquired the remaining 49.0% non-controlling interest in an O-Tex subsidiary for $1.25 million.

The O-Tex transaction was accounted for using the acquisition method of accounting for business combinations. The preliminary purchase price was allocated to the net assets acquired based upon their estimated fair values. The estimated fair values of certain assets and liabilities, including property plant and equipment, other intangible assets, and contingencies required significant judgments and estimates. As a result, the provisional measurements are preliminary and subject to change during the measurement period and such changes could be material.

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C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

During the second quarter of 2018, C&J and the seller agreed to a working capital adjustment of $1.5 million in favor of C&J, which was accounted for as a reduction to the purchase price of O-Tex.

The following unaudited pro forma results of operations have been prepared as though the O-Tex transaction was completed on January 1, 2016. Pro forma amounts are based on the purchase price allocation of the acquisition and are not necessarily indicative of results that may be reported in the future (in thousands):



	Six Months Ended June 30, 2017
Revenues	$	783,635
Net loss	$	(48,579	)

Note 9 - Supplemental Cash Flow Disclosures

Listed below are supplemental cash flow disclosures for the six months ended June 30, 2018 and 2017 and the Fresh Start Reporting Date:



	Successor						Predecessor
	Six Months Ended June 30, 2018			Six Months Ended June 30, 2017			On January 1, 2017
Cash paid for interest	$	(821	)	$	(914	)	$	—
Income taxes refunded, net	$	4,069		$	488		$	—
Reorganization items, cash	$	—		$	—		$	(21,657	)
Non-cash investing and financing activity:
Change in accrued capital expenditures	$	4,800		$	(3,127	)	$	—

Note 10 - Subsequent Events

On July 31, 2018, the Company’s Board of Directors approved a stock repurchase program authorizing the repurchase of up to $150.0 million of the Company’s common stock over a twelve month period starting August 1, 2018. Repurchases may commence or be suspended at any time without notice. The program does not obligate the Company to purchase a specified number of shares of common stock during the period or at all, and may be modified or suspended at any time at the Company’s discretion.

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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This Quarterly Report on Form 10-Q (this “Quarterly Report”) 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,” “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 business strategy and our financial strategy.

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, risks associated with the following:


•	a decline in demand for our services, including due to supply of oil and gas, declining or perceived instability of commodity prices, overcapacity of supply, constrained pipeline capacity, and other competitive factors affecting our industry;


•	the cyclical nature and volatility of the oil and gas industry, which impacts the level of drilling, completion and production activity and spending patterns by our customers;


•	a decline in, or substantial volatility of, crude oil and gas commodity prices, which generally leads to decreased spending by our customers and negatively impacts drilling, completion and production activity;


•	pressure on pricing for our services, including due to competition and industry and/or economic conditions, which impacts, among other things, our ability to implement price increases or maintain pricing on our services;


•	the loss of, or interruption or delay in operations by, one or more significant customers;


•	the failure by one or more of our significant customers to pay amounts when due, or at all;


•	changes in customer requirements in the markets we serve;


•	costs, delays, compliance requirements and other difficulties in executing our short-and long-term business plans and growth strategies;


•	the effects of recent or future acquisitions on our business, including our ability to successfully integrate our operations and the costs incurred in doing so;


•	business growth outpacing the capabilities of our infrastructure;


•	operating hazards inherent in our industry, including the possibility of accidents resulting in personal injury or death, property damage or environmental damage;


•	adverse weather conditions in oil or gas producing regions;


•	the loss of, or interruption or delay in operations by, one or more of our key suppliers;


•	the effect of environmental and other governmental regulations on our operations, including the risk that future changes in the regulation of hydraulic fracturing could reduce or eliminate demand for our hydraulic fracturing services;


•	the incurrence of significant costs and liabilities resulting from litigation or governmental proceedings;


•	the incurrence of significant costs and liabilities or severe restrictions on our operations or the inability to perform certain operations or provide certain services resulting from a failure to comply, or our compliance with, new or existing regulations;


•	the effect of new or existing regulations, industry and/or commercial conditions on the availability of and costs for raw materials, consumables and equipment;

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•	the loss of, or inability to attract, key management and other competent personnel;


•	a shortage of qualified workers;


•	damage to or malfunction of equipment;


•	our ability to maintain sufficient liquidity and/or obtain adequate financing to allow us to execute our business plan; and


•	our ability to comply with covenants under our debt facilities.

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 Quarterly Report, as well as “Risk Factors” in Part I, Item 1A in our Annual Report on Form 10-K for the fiscal year ended December 31, 2017 (our “2017 Annual Report”); and (2) “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Part I, Item 2 of this Quarterly Report, as well as “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Part II, Item 7 of our 2017 Annual Report. 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.

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

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the accompanying unaudited consolidated financial statements and the related notes thereto included elsewhere in this Quarterly Report, together with the audited consolidated financial statements and notes thereto and Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations” included in our 2017 Annual Report.

This Quarterly Report contains forward-looking statements that involve risks and uncertainties. Our actual results may differ materially from those discussed in any forward-looking statement because of various factors, including those described in the sections titled “Cautionary Note Regarding Forward-Looking Statements” and “Risk Factors” in Part II, Item 1A of this Quarterly Report.

Introductory Note and Overview

C&J Energy Services, Inc., a Delaware corporation (“C&J,” the “Company,” “we,” “us” or “our”), is a leading provider of well construction and intervention, well completion, well support and other complementary oilfield services and technologies to independent and major oilfield companies engaged in the exploration, production and development of oil and gas properties in onshore basins throughout the continental United States. We are a new well-focused service provider and we offer a diverse, integrated suite of services across the life cycle of the well, including hydraulic fracturing, cased-hole wireline and pumping, cementing, coiled tubing, rig services, fluids management and other completions-focused and specialty well site support services.

We were founded in Texas in 1997 and are headquarters are in Houston, Texas. On April 12, 2017, following the successful completion of a financial restructuring (see Note 2 - Chapter 11 Proceeding and Emergence in Part I, Item 1 “Financial Statements” of this Quarterly Report), we completed an underwritten public offering of common stock and began trading on the New York Stock Exchange (“NYSE”) under the symbol “CJ.”

Our revenues and profits are generated by providing services and equipment to customers who operate oil and gas properties and invest capital to drill and complete new wells and enhance production or perform maintenance on existing wells. Please read "Reportable Segments" and "Operating Overview" in this Part I, Item 2 "Management’s Discussion and Analysis of Financial Condition and Results of Operations", for a discussion of our operations and key business and financial strategies. Please read "Industry Trends and Outlook" in this Part I, Item 2 "Management’s Discussion and Analysis of Financial Condition and Results of Operations" for a discussion of certain trends and factors that impact our operational and financial performance.

We file annual, quarterly and current reports and other documents with the U.S. Securities and Exchange Commission (“SEC”) under the Exchange Act. You may read and copy any materials we file with the SEC at the SEC’s Public Reference Room at 100 F Street, NE, Washington, DC 20549. You may obtain information on the operations of the Public Reference Room by calling the SEC at (800) SEC-0330. In addition, the SEC maintains a website at www.sec.gov that contains reports and other information regarding issuers that file electronically with the SEC.

Our principal executive offices are located at 3990 Rogerdale Road, Houston, Texas 77042 and our main telephone number at that address is (713) 325-6000. Our website is available at www.cjenergy.com. We make available free of charge through our website all reports filed with or furnished to the SEC pursuant to Section 13(a) or 15(d) of the Exchange Act, including our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, Proxy Statement on Schedule 14A and all amendments to those reports, as soon as reasonably practicable after such material is electronically filed with or furnished to the SEC. Information contained on or available through our website is not a part of or incorporated into this Quarterly Report or any other report that we may file with or furnish to the SEC.

Recent Developments

On July 31, 2018, the Company's Board of Directors approved a stock repurchase program authorizing the repurchase, at the discretion of senior management, of up to $150.0 million of the Company’s common stock over the twelve month period starting August 1, 2018, in open market or in privately negotiated transactions, subject to U.S. Securities and Exchange Commission regulations, stock market conditions, capital needs of the business, and other factors. Repurchases may be commenced or suspended at any time without notice. The program does not obligate C&J to purchase any particular number of shares of common stock during any period or at all, and the program may be modified or suspended at any time in the Company’s discretion.

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Reportable Segments

During the first quarter of 2018, we revised our reportable segments. As a result of the revised reportable segment structure, we have restated the corresponding items of the segment information for all periods presented. As of June 30, 2018, our reportable business segments were:


•	Completion Services, which consisted of the following businesses and service lines: (1) fracturing services; (2) cased-hole wireline and pumping services; and (3) completion support services, which includes logistics services and our research and technology (“R&T”) department.


•	Well Construction and Intervention Services, which consisted of the following businesses and service lines: (1) cementing services; (2) coiled tubing services; and (3) directional drilling services.


•	Well Support Services, which consisted of the following businesses and service lines: (1) rig services; (2) fluids management services; and (3) special services, which included plug and abandonment, artificial lift applications and other specialty well site services.

During the first quarter of 2018, we decided to exit our directional drilling business and artificial lift business. We ceased directional drilling operations during the first quarter of 2018 and we are in the process of divesting the assets and inventory associated with that business. We completed the sale of substantially all of the assets and inventory associated with the artificial lift business on July 2, 2018.

Our reportable business segments are described in more detail below; for financial information about our reportable business segments, including revenue from external customers and total assets by reportable business segment, please see Note 7 - Segment Information in Part I, Item 1 “Financial Statements” of this Quarterly Report.

Completion Services

The core services provided through our Completion Services segment are fracturing and cased-hole wireline and pumping services. Our completion support services are focused on supporting the efficiency and effectiveness of our operations, including a logistics services department, the primary purpose of which is to satisfy a portion of our internal sand hauling needs. Our R&T department provides in-house manufacturing capabilities that help to reduce operating cost and enable us to offer more technologically advanced and efficiency focused completion services, which we believe is a competitive differentiator. For example, through our R&T department we manufacture the data control instruments used in our fracturing operations and the perforating guns and addressable switches used in our wireline operations; these products are also sold to third-parties. The majority of revenue for this segment is generated by our fracturing business.

During the second quarter of 2018, our fracturing business deployed, on average, approximately 675,000 hydraulic horsepower (“HHP”) out of a fleet of approximately 900,000 HHP as of June 30, 2018. We exited the second quarter of 2018 with approximately 735,000 HHP deployed, consisting of seventeen horizontal and two vertical frac fleets, after redeploying two refurbished horizontal frac fleets during the quarter. Our typical horizontal fleet size consists of 20 pumps, or approximately 40,000 HHP, and our typical vertical fleet size consists of 10 pumps, or approximately 20,000 HHP. In our cased-hole wireline and pumping business, during the second quarter of 2018, we deployed, on average, approximately 69 wireline trucks and 76 pumpdown units out of our fleet of 124 trucks and 79 pumpdown units, respectively, as of June 30, 2018. Not all of our deployed assets are utilized fully, or at all, at any given time, due to, among other things, routine scheduled maintenance and downtime.

The following table presents revenue, Adjusted EBITDA and certain operational data for our Completion Services segment for the second quarter of 2018, the first quarter of 2018, and the second quarter of 2017. Please read Note 7 - Segment Information in Part I, Item 1 “Financial Statements” of this Quarterly Report, for the definition and calculation of Adjusted EBTIDA as well as a reconciliation of Adjusted EBITDA, a non-GAAP financial measure, from net income (loss), which is the nearest comparable U.S. GAAP financial measure, for the periods presented. Management evaluates the operational performance of our Completion Services segment and allocates resources primarily based on Adjusted EBITDA because management believes that Adjusted EBITDA provides important information about the activity and profitability of our lines of business within this segment. For additional information, please also read “Operating Overview” in this Part I, Item 2 “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

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	Three Months Ended
	June 30, 2018		March 31, 2018		June 30, 2017
	(in thousands)
Revenue
Fracturing	$	288,855	$	269,491	$	183,714
Cased-hole Wireline & Pumping	115,377		99,754		76,644
Other	8,663		4,900		2,522
Total revenue	$	412,895	$	374,145	$	262,880

Adjusted EBITDA	$	83,252	$	80,894	$	45,114

Average active hydraulic fracturing horsepower	675,000		630,000		490,000
Total fracturing stages	4,823		4,652		3,688

Average active wireline trucks	69		67		72

Average active pumpdown units	76		72		62

During the second quarter of 2018, we experienced sequential improvement in both revenue and Adjusted EBITDA for our Completion Services segment with the deployment of two additional 40,000 HHP horizontal frac fleets deployed in the mid- to latter- half of the quarter, as well as additional pumpdown units placed into service during the quarter. These results also reflect the full quarter impact of a horizontal frac fleet deployed in late March 2018. In our fracturing business, revenue increased but profitability decreased, the latter primarily due to a decline in utilization late in the second quarter, as well as some pricing weakness and higher consumable costs that we were not able to fully pass on to our customers. Specifically, we maintained strong utilization through much of the quarter but then experienced declines in utilization and pricing in June 2018, most prominently in West Texas as customers paused activity to evaluate pipeline constraint concerns and widening basis differential. We also had several dedicated frac fleet agreements terminate during the second quarter, some expiring at the end of the contracted term and others terminating early at the election of the customer in accordance with the agreements. This increased our exposure to the spot market, resulting in lower utilization and pricing levels. This has continued into the third quarter. Our strategy includes partnering with high quality customers under dedicated agreements, and we are currently in contract negotiations for these previously dedicated fleets with both new and existing customers. However, it is uncertain whether we will be successful in executing new agreements at all, or with pricing, utilization and other terms as favorable as those that terminated. Second quarter profitability for our fracturing business was also impacted by a lack of contracted regional sand in West Texas, which we believe is a transitory issue.

Given the decline in customer demand that we were experiencing, which translated into lower utilization and pricing levels, coupled with uncertainty regarding future market conditions for completion services and our ability to capture improved utilization and pricing, in June 2018, we decided to suspend capital spending on the refurbishment of our three remaining stacked frac fleets, the first of which we were working to redeploy in October 2018. In keeping with our returns-focused philosophy, we intend to delay redeployment of this 120,000 hydraulic horsepower, until customer demand and market conditions improve.

In our cased-hole wireline and pumping business, we grew market share, deployed additional equipment, and captured strong utilization and higher pricing, primarily for certain auxiliary services provided at the well site. Our results also benefited from increased customer efficiencies and the introduction of new technologies. As with our fracturing services, we experienced some weakness in demand for these services during the latter part of the second quarter, primarily in West Texas. However, the impact was not as significant as it was for fracturing services due to the geographic footprint of these businesses. Approximately 70% of second quarter revenue contributed from these businesses was generated from basins outside of West Texas. In our wireline business, we experienced improvement in both revenue and profitability in many of our operating basins, and we benefited from an increased percentage of super-pads in select basins that allowed us to utilize more equipment with smaller crew sizes. Additionally, customer demand remained strong in our pumping business, and we deployed five additional units into service with strong utilization and pricing levels.

Well Construction and Intervention Services

The core services provided through our Well Construction and Intervention Services segment are cementing and

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coiled tubing services. Although we previously provided directional drilling services through this segment, we ceased operations during the first quarter of 2018 and we are in the process of selling the related assets and inventory. The majority of revenue for this segment is generated by our cementing business.

During the second quarter of 2018, our cementing business deployed, on average, approximately 73 cementing units out of our fleet of 115 units as of June 30, 2018; and in our coiled tubing business, we deployed, on average, approximately 16 coiled tubing units during the quarter out of our fleet of 46 units at quarter end. Our deployed assets may not be utilized fully, or at all, at any given time, due to, among other things, routine scheduled maintenance and downtime.

The following table presents revenue, Adjusted EBITDA and certain operational data for our Well Construction and Intervention Services segment for the second quarter of 2018, the first quarter of 2018, and the second quarter of 2017. Please read Note 7 - Segment Information in Part I, Item 1 “Financial Statements” of this Quarterly Report, for the definition and calculation of Adjusted EBTIDA as well as a reconciliation of Adjusted EBITDA, a non-GAAP financial measure, from net income (loss), which is the nearest comparable U.S. GAAP financial measure, for the periods presented. Management evaluates the operational performance of our Well Construction and Intervention Services segment and allocates resources primarily based on Adjusted EBITDA because management believes that Adjusted EBITDA provides important information about the activity and profitability of our lines of business within this segment. For additional information, please also read “Operating Overview” in this Part I, Item 2 “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”



	Three Months Ended
	June 30, 2018		March 31, 2018		June 30, 2017
	(in thousands)
Revenue
Cementing	$	69,328	$	61,548	$	12,432
Coiled Tubing	29,758		25,788		18,577
Other	—		81		258
Total revenue	$	99,086	$	87,417	$	31,267

Adjusted EBITDA	$	19,632	$	16,001	$	2,667

Average cementing units	118		117		34
Average active cementing units	73		71		29

Average coiled tubing units	45		44		44
Average active coiled tubing units	16		17		21

In our Well Construction and Intervention Services segment, revenue and Adjusted EBITDA for the second quarter of 2018 increased sequentially, primarily due to growth in market share, the deployment of additional equipment, and higher utilization and pricing, all stemming from strong customer demand. In our cementing business, we experienced increased pricing and utilization levels in core operating basins, and we benefited from the deployment of four additional units in West Texas to both new and existing customers during the quarter. In our coiled tubing business, we benefited from the deployment of two new-build large diameter high capacity units with 2-5/8'' tubing late in the quarter. Demand for large diameter coil has remained strong and our large diameter units accounted for approximately 90% of the revenue and profitability generated in our coiled tubing business for the second quarter of 2018.

Well Support Services

Our Well Support Services segment focuses on post-completion activities at the well site, including rig services, such as workover and plug and abandonment, fluids management services, and other specialty well site services. Although we provided artificial lift applications through this segment, we completed the sale of substantially all of the assets and inventory associated with this business on July 2, 2018. Additionally, in response to the highly competitive landscape and reflecting our returns-focused strategy, we have continued to focus on operational rightsizing measures to better align these businesses with current market conditions, which has included closing facilities and idling unproductive equipment. For example, during the fourth quarter of 2017, we divested our Canadian rig services business, during the first quarter of 2018, we exited the

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condensate hauling business in South Texas, and late in the second quarter of 2018, we shut-down our East Texas rig services operations. The majority of revenue for this segment is generated by our rig services business, and we consider rig services and fluids management to be the core businesses within this segment.

During the second quarter of 2018, our rig services business deployed, on average, approximately 118 workover rigs per workday out of our average fleet of approximately 352 marketable workover rigs. In our fluids management business, we deployed, on average, approximately 636 fluid services trucks per workday and approximately 1,326 frac tanks per workday out of our estimated average fleets of approximately 981 trucks and 3,190 frac tanks, respectively. In our fluids management business, we own 23 private salt water disposal wells for fluids disposal purposes. However, not all of our deployed assets are utilized fully, or at all, at any given time, due to, among other things, routine scheduled maintenance and downtime.

The following table presents revenue, Adjusted EBITDA, and certain operational data for our Well Support Services segment for the second quarter of 2018, the first quarter of 2018, and the second quarter of 2017. Please read Note 7 - Segment Information in Part I, Item 1 “Financial Statements” of this Quarterly Report, for the definition and calculation of Adjusted EBITDA as well as a reconciliation of Adjusted EBITDA, a non-GAAP financial measure, from net income (loss), which is the nearest comparable U.S. GAAP financial measure, for the periods presented. Management evaluates the operation and performance of our Well Support Services segment and allocates resources based on activity levels, specifically rig and trucking hours, as well as Adjusted EBITDA because management believes that Adjusted EBITDA provides important information about the activity and profitability of our lines of business within this segment. For additional information, please also read “Operating Overview” in this Part I, Item 2 “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”



	Three Months Ended
	June 30, 2018		March 31, 2018		June 30, 2017
	(in thousands)
Revenue
Rig Services	$	51,716	$	48,445	$	54,022
Fluids Management	34,128		31,795		32,141
Other Special Well Site Services	12,696		11,198		9,833
Total revenue	$	98,540	$	91,438	$	95,996

Adjusted EBITDA	$	10,933	$	5,107	$	1,927

Average active workover rigs	118		140		132
Total workover rig hours	93,911		92,428		101,872

Average fluids management trucks	981		1,064		1,121
Average active fluids management trucks	636		616		651
Total fluids management truck hours	310,445		307,002		318,111

Well Support Services segment revenue and Adjusted EBITDA for the second quarter of 2018 increased compared to the first quarter of 2018 due to higher customer activity levels and improved pricing. Adjusted EBITDA for the second quarter of 2018 sequentially improved despite ongoing losses from our recently divested artificial lift business, which we completed early in the third quarter of 2018. In our rig services business, we focused on customers with consistent levels of higher margin work, which in combination with higher pricing resulted in improved revenue and profitability in core basins such as South Texas and California. In our fluids management business, increased 24-hour completion activity resulted in greater demand for our fluids logistics and disposal services, especially in areas with minimal infrastructure build-out. We captured higher activity levels and pricing for these services in many of our core operating basins, which contributed to our improved financial results.

Operating Overview & Strategy

Our revenues and profits are generated by providing services and equipment to customers who operate oil and gas properties and invest capital to drill new wells and enhance production or perform maintenance on existing wells. Our results of operations in our core service lines are driven primarily by five interrelated, fluctuating variables: (1) the drilling,

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completion and production activities of our customers, which is primarily driven by oil and natural gas prices and directly affects the demand for our services; (2) the price we are able to charge for our services and equipment, which is primarily driven by the level of demand for our services and the supply of equipment capacity in the market; (3) the cost of materials, supplies and labor involved in providing our services, and our ability to pass those costs on to our customers; (4) our activity, or “utilization” levels; and (5) the quality, safety and efficiency of our service execution.

We continuously monitor factors that impact our asset utilization and pricing levels; significantly including current and expected customer activity levels. Historically, our utilization levels have been highly correlated to U.S. onshore spending by our customers, which is heavily driven by the price of oil and natural gas. Generally, as capital spending by our customers increases, their drilling, completion and production activity also increases, resulting in increased demand for our services, and therefore more days or hours worked (as the case may be). Conversely, when drilling, completion and production activity levels decline due to lower spending by our customers, we generally provide fewer services, which results in fewer days or hours worked (as the case may be). Additionally, during periods of decreased spending by our customers, we may be required to discount our rates or provide other pricing concessions to remain competitive and support utilization, which negatively impacts our revenue and operating margins. During periods of pricing weakness for our services, we may not be able to reduce our costs accordingly, and our ability to achieve any cost reductions from our suppliers typically lags behind the decline in pricing for our services, which further adversely affects our results. For additional information about factors impacting our business and results of operations, please see “Industry Trends and Outlook” in this Part I, Item 2 “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

Our operating strategy continues to be focused on maintaining high asset utilization levels to maximize revenue generation while controlling cost to drive returns. We believe that the quality, safety and efficiency of our service execution and partnering with customers who recognize the value that we provide are central to our efforts to support utilization and pricing levels and our ongoing performance. Asset utilization, among other factors, is helpful for purposes of assessing our overall activity levels and customer demand. However, given the variance in revenue and profitability from job to job, depending on the type of service to be performed and the equipment, personnel and consumables required for the job, as well as competitive factors and market conditions in the region in which the services are performed, asset utilization is not necessarily indicative of our financial and/or operational performance and should not be given undue reliance. Due to the volatile and cyclical nature of activity drivers in the U.S. onshore oilfield services industry, coupled with the varying prices we are able to charge for our services and equipment, and the cost of providing those services and equipment, among numerous other factors, operating margins can fluctuate widely.

Revenue, Adjusted EBITDA and certain operational data indicative of utilization levels is provided for each of our operating segments under “Reportable Segments” in this Part I, Item 2 “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

•For our Completion Services operations, we measure our asset utilization levels primarily by the total number of days that our asset base works on a monthly basis, based on the available working days per month, which excludes scheduled maintenance days. We generally consider an asset to be working such days that it is at or in transit to a job location, regardless of the number of hours worked or whether it generated any revenue during such time.

•In our Well Construction and Intervention Services segment, we measure our asset utilization levels primarily by the total number of days that our asset base works on a monthly basis, based on the available working days per month. In our coiled tubing business, we measure certain asset utilization levels by the hour to better understand measures between daylight and 24-hour operations. Both the financial and operating performance of our coiled tubing and cement units can vary in revenue and profitability from job to job depending on the type of service to be performed and the equipment, personnel and consumables required for the job, as well as competitive factors and market conditions in the region in which the services are performed.

•In our Well Support Services operations, we measure activity levels primarily by the number of hours our assets work on a monthly basis, based on the available working days per month

Management evaluates the financial performance of our reportable business segments primarily based on Adjusted EBITDA because management believes Adjusted EBITDA provides important information about the activity and profitability of our lines of business within each reportable business segment and aids us in analytical comparisons for purposes of, among other things, efficiently allocating our assets and resources. Please read Note 7 - Segment Information in Part I, Item 1 “Financial Statements” of this Quarterly Report, for the definition and calculation of Adjusted EBTIDA, as well as a reconciliation of Adjusted EBITDA, a non-GAAP financial measure, from net income (loss), which is the nearest comparable U.S. GAAP financial measure. Additionally, as required under Item 10(e) of Regulation S-K of the Exchange Act, included

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below is a reconciliation of Adjusted EBITDA, a non-GAAP financial measure, from net income (loss), which is the nearest comparable U.S. GAAP financial measure (in thousands) on a consolidated basis for the three months ended June 30, 2018, March 31, 2018 and June 30, 2017.



	Three Months Ended
	June 30, 2018			March 31, 2018			June 30, 2017
Net income (loss)	$	28,496		20,594			$	(12,721	)
Interest expense, net	2,185			428			414
Income tax benefit	(893		)	(60		)	(2,393		)
Depreciation and amortization	54,387			46,343			32,833
Other (income) expense, net	1,106			(620		)	1,456
(Gain) loss on disposal of assets	49			(489		)	(3,136		)
Acquisition-related and other transaction costs	243			727			298
Severance and business divestiture costs	40			6,140			513
Restructuring costs	2,163			623			7,846
Adjusted EBITDA	$	87,776		$	73,686		$	25,110

Industry 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 the factors described in the sections titled “Cautionary Note Regarding Forward-Looking Statements” in Part I, Financial Information and “Risk Factors” in Part II, Item 1A of this Quarterly Report for additional information about the known material risks that we face.

General Industry Trends

The oil and gas industry has traditionally been volatile and is influenced by a combination of long-term, short-term and cyclical trends, including domestic and international supply and demand for oil and gas, current and expected future prices for oil and gas and the perceived stability and sustainability of those prices, production depletion rates and the resultant levels of cash flows generated and allocated by oil and gas companies to their drilling, completion and workover budgets. The oil and gas industry is also impacted by geopolitical factors, such as general domestic and international economic conditions, the actions of the OPEC oil cartel, political instability in oil producing countries, government regulations (both in the United States and elsewhere), levels of consumer demand, the availability of pipeline capacity, weather conditions in the U.S., and other factors that are beyond our control.

Demand for our services tends to be volatile and cyclical because it is a direct function of our customers’ willingness to make operating and capital expenditures to explore for, develop and produce hydrocarbons in the United States. Our customers’ willingness to undertake such activities and make such expenditures depends largely upon prevailing industry conditions, which are influenced by numerous factors that are beyond our control, including, among others, those described above. The current and projected prices of oil, natural gas and natural gas liquids are important catalysts for customer activity levels. Perceived instability or weakness in oil and natural gas prices influences our customers to pause activity, curtail their operations, reduce their expenditures, and request pricing concessions to reduce their operating costs. In a lower oil and gas price environment, demand for service and maintenance generally decreases as oil and gas producers decrease their activity and operating and capital expenditures. Because the type of services that we offer can be easily “started” and “stopped,” and oil and gas producers generally tend to be less risk tolerant when commodity prices are low or volatile, we typically experience a more rapid decline in demand for our services compared with demand for other types of energy services. Given the significant influence of oil and gas prices, customer activity levels historically have been, and are expected to continue to be, highly volatile. A prolonged low level of customer activity could adversely affect our financial condition and results of operations.

Severe declines and sustained weakness and volatility in commodity prices over the course of 2015, and for most of 2016, and the consequent negative impact on customer activity levels and expenditures, adversely affected the demand for our services. This, in turn, negatively impacted our ability to maintain adequate utilization of our asset base and pricing at levels generating sufficient margins. The adverse impact to our financial and operational performance ultimately led to the

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Company’s Chapter 11 Proceeding (see Note 2 - Chapter 11 Proceeding and Emergence in Part I, Item 1 “Financial Statements” of this Quarterly Report).

Competition and Demand for Our Services

Our revenue and profitability are directly affected by changes in utilization and pricing levels for our services, which fluctuate in direct response to changes in the level of drilling, completion and production activity by our customers. Declines in utilization or pricing for our services impact, among other things, our ability to maintain revenue and profitability. During periods of declining pricing for our services, we may not be able to reduce our costs accordingly, which could further adversely affect our results. Furthermore, even when we are able to increase our prices, we may not be able to do so at a rate that is sufficient to offset any rising costs. Also, we may not be able to successfully increase prices without adversely affecting our utilization levels. The inability to maintain our utilization and pricing levels, or to increase our prices as costs increase, could have a material adverse effect on our business, financial position and results of operations.

We operate in highly competitive areas of the oilfield services industry with significant potential for excess capacity. With respect to all of our core services, the equipment can be moved with relative ease from one region to another in response to changes in customer activities and market conditions, which can result in an oversupply of equipment in high activity areas. Increases in supply relative to demand in our core operating areas and geographic markets has in the past negatively impacted both pricing and utilization for our services and adversely affected our financial results.

As the industry has recovered from the historic downturn, competition has increased, both from new entrants into the oilfield services industry and from established competitors who are adding to their revenue-producing asset base. Our competitors include many large and small energy service companies, including some of the largest integrated oilfield services companies that possess substantially greater financial and other resources than we do. Our larger competitors’ greater resources could allow them to compete more effectively than we can, including by reducing prices for services in our core operating areas. Our major competitors for both our Completion Services and Well Construction and Intervention Services segments include Halliburton, Schlumberger, BJ Services, Keane Group, RPC, Inc., FTS International, Inc., ProPetro Holding Corp., Basic Energy Services, Superior Energy Services, CalFrac Well Services, as well as a significant number of regional, predominantly private businesses. Our major competitors for our Well Support Services include Key Energy Services, Basic Energy Services, Superior Energy Services, Precision, Forbes, Pioneer Energy Services and Ranger Energy Services, as well as a significant number of predominantly private, regional businesses.

Generally, we believe that the principal competitive factors in the markets that we serve are price, technical expertise, equipment capacity, work force capability, safety record, reputation and experience. Although we believe our customers consider all of these factors, price is often the primary factor in determining which service provider is awarded work, particularly during times of weak commodity prices such as those we experienced from late 2014 through the majority of 2016. Throughout this severe, prolonged downturn for our industry, our customer base demonstrated a more intense focus and placed a higher priority on receiving the lowest service cost pricing possible. Additionally, projects for certain of our core service lines are often awarded on a bid basis, which tends to further increase competition based primarily on price. During the downturn and even during healthier environments, our utilization and pricing levels have been negatively impacted by predatory pricing from competitors. Also, with the increase in competition both from new entrants into the oilfield services industry and from established competitors who are adding to their fleets of revenue-producing equipment, we have not been able to significantly increase pricing for our core services.

During healthier market conditions, we believe many of our customers choose to work with us based on the safety, performance and quality of our crews, equipment and services, although even then, we must be competitive with our pricing. We seek to differentiate ourselves from our major competitors by our operating philosophy, which is focused on delivering the highest quality customer service and equipment, coupled with superior execution and operating efficiency. As part of this strategy, we target high efficiency customers with service intensive, 24-hour work, which is where we believe we can differentiate our services from those of our competitors. Our strategy includes partnering with high quality customers under dedicated agreements.

Regulations

The discussion set forth under Item 1. "Business - Government Regulations and Environmental, Health and Safety Matters" in our 2017 Annual Report is incorporated herein by reference.

On March 8, 2018, the President issued two Proclamations directing the imposition, effective March 23, 2018, of ad valorem tariffs of 25% on certain imported steel products and 10% on certain imported aluminum products from all

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countries, with the exception of Canada and Mexico. Subsequently, on March 22, 2018, the President issued two additional Proclamations that exempted, in addition to Canada and Mexico, several additional countries from the remedial tariff measures, as follows: (i) Argentina; (ii) Australia; (iii) Brazil; (iv) the 28 member countries of the European Union; and (v) South Korea. In Proclamations issued on April 30, 2018, the President: (i) permanently exempted South Korea from the imposition of tariffs on imported steel, while allowing tariffs to be imposed on imported aluminum; (ii) extended the steel and aluminum tariff exemptions for Argentina, Australia, and Brazil indefinitely to allow for continued negotiations; and (iii) extended the steel and aluminum tariff exemptions for Canada, Mexico, and the 28 member countries of the European Union to allow for continued negotiations, but only through May 31, 2018. In addition to possible country-based exemptions, the United States has established a protocol whereby individuals or entities using any of the affected steel or aluminum products in business activities, such as manufacturing, may request the exclusion of individual products from the imposition of tariffs. On May 31, 2018, the U.S. announced that it would also impose steel and aluminum tariffs on Canada, Mexico, and the 28 member countries of the European Union. In addition, Argentina, Australia, Brazil, and South Korea implemented measures to address the impairment to U.S. national security attributable to steel and aluminum imports that were deemed satisfactory to the United States. As a result, imports of steel and/or aluminum from these countries have been exempted from the imposition of tariff-based remedies, but, with the exception of Australia, the United States has implemented quantitative restrictions in the form of absolute quotas, meaning that imports in excess of the allotted quota will be disallowed.

Our R&T department is primarily engaged in the engineering and production of certain parts and components, such as perforating guns and addressable switches, which are used in the completion process. Certain of these items, particularly perforating guns used in our wireline operations, are manufactured using imported steel tubing, which is subject to a 25% tariff. We expect that, depending on the ultimate outcome of the country exemption and product exclusion processes described above, our raw material costs will increase and result in corresponding increases in the price of our finished goods. Further, in addition to the products manufactured by our R&T department, we expect that the costs of other high steel content products used in conjunction with our fracturing and coiled tubing operations, specifically power ends, fluid ends, treating iron and coiled tubing strings, will also increase as we expect the manufacturers of such goods to pass along the net effect the tariffs have on the cost of manufacturing such goods.

Current Market Conditions and Outlook

In late 2014, oil prices began a substantial and rapid decline, and the severe weakness continued throughout 2015 and the majority of 2016. As we entered 2016, we experienced a sharp drop in activity across our customer base as operators reacted to further declines in oil prices and the deteriorating onshore drilling rig count. The consequent negative impact on the level of drilling, completion and production activity and capital and operating expenditures by our customers adversely affected the demand for our services throughout the severe industry downturn, which in turn adversely impacted our financial and operational performance. In July 2016, we filed voluntary petitions for reorganization (seeking relief under the provisions of Chapter 11 of the Bankruptcy Code (see Note 2 - Chapter 11 Proceeding and Emergence in Part I, Item 1 “Financial Statements” of this Quarterly Report).

The prices of oil and natural gas began to increase modestly and stabilize over the latter part of 2016, and have generally remained so, although at levels significantly lower than experienced prior and leading up to the downturn. For example, during February 2016, NYMEX crude oil prices reached their lowest levels since 2009, declining to as low as $26.21 per barrel. Crude oil prices have rebounded from the lows set in early 2016, and during the second quarter of 2018, prices have averaged approximately $68.00 per barrel. Natural gas prices declined significantly in 2009 and have remained depressed relative to pre-2009 levels. During 2017 and into 2018, the price of oil generally continued to rise, and we believe it is currently stabilized at a level that provides adequate financial returns to our customers and should encourage increased drilling, completion and production activities in many domestic oil-producing basins; whereas, the price of gas has not risen to a level that would encourage such activities. Our results for the first half of 2018, reflect these constructive market dynamics.

During the second quarter of 2018, the industry experienced concerns that growing oil production in West Texas may temporarily exceed the capacity of the region’s pipelines to transport oil from oil wells to oil refineries. We have a significant operating presence in this area and our financial results for the second quarter of 2018 were negatively impacted by customer reactions to these concerns. Our Completion Services businesses experienced declines in utilization and pricing in the latter part of the second quarter. Our fracturing business was the most significantly impacted, stemming from customer driven activity gaps coupled with the termination of several dedicated fracturing agreements, which increased our exposure to the spot market. These dynamics have continued into the third quarter, with continuing weakness in completion activity. If these conditions persist and the pipelines become constrained, this could force our customers in the region to reduce their activities, which represents a risk to our near-term financial results. We have continued to benefit from our geographic and product line diversity that positions us in many markets that have remained strong. However, like C&J, our competitors also have the ability to rapidly move assets and crews between basins as market conditions change.

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We continue to monitor the market for our services and the competitive environment. The U.S. domestic rig count has increase since the historical low recorded during the second quarter of 2016, which has increased demand and pricing for our services. We are encouraged by the fact that drilling and completion activities continue to be highly service-intensive and require a large amount of equipment and raw materials. Furthermore, we believe that prevailing commodity prices and the near term outlook have positive implications for our near-term performance, as we provide many of the types of services required by our customers in the industry environment. However, increasing competition, logistical constraints and other factors and trends represent a risk to our near-term financial results and may negatively impact our performance for the remainder of 2018.

We actively monitor the market for our services and the competitive environment. We seek to manage our business in line with demand for services and try to make adjustments as necessary to effectively respond to changes in market conditions, customer activity levels, pricing for our services and equipment, and utilization of our equipment and personnel. Our consistent response to the industry's persistent uncertainty is to maintain sufficient liquidity and a conservative capital structure and monitor our discretionary spending. We intend to maintain a financial structure that includes little or no debt during the near term. We take a measured approach to asset deployment, balancing our view of current and expected customer activity levels with a focus on generating positive returns for our shareholders. Our priorities remain to drive revenue by maximizing utilization, to improve margins through cost controls, to protect and grow our market share by focusing on the quality, safety and efficiency of our service execution, and to ensure that we are strategically positioned to capitalize on constructive market dynamics.

Completion Services Outlook

The weakness in completion activity that we experienced towards the end of the second quarter has continued, resulting in lower utilization and pricing levels, particularly for fracturing services. We had several dedicated frac fleet agreements terminate during the second quarter, which increased our exposure to the spot market. We deployed our eighteenth horizontal frac fleet to a dedicated customer in West Texas in late July 2018, and we currently are in negotiations to place certain of our previously dedicated fleets with new and existing customers. It is uncertain whether we will be able to successfully negotiate new contracts for these fleets with favorable utilization, pricing and other terms, or capture adequate utilization and pricing arrangements for them at all. Our strategy to improve utilization includes targeting existing, long-time customers to increase their dedicated horsepower and relocating equipment to areas with stronger demand. In our cased-hole wireline and pumping business, we are currently planning to deploy more equipment over the remainder of 2018, as well as new technologies that are expected to enhance our profitability. However, whether and when we deploy these units depends on customer demand and market conditions. We are also targeting more high-margin ancillary services at the well site.

Well Construction and Intervention Services Outlook

We currently expect that our Well Construction and Intervention Services segment will continue to experience stable customer demand through the second half of the year, subject to the typical slowdown and delays at year end. In our cementing business, we are focused on capturing increased operational efficiencies and meet growing customer demand by deploying additional resources to the Delaware Basin. In our coiled tubing business, a full quarter impact from the two new-build large diameter units that we deployed in the second quarter should benefit our third quarter 2018 results, and we are planning to reallocate coiled tubing assets into operating basis with stronger customer demand. However, our ability to continue to grow the businesses in this segment is impacted by our ability to recruit and retain skilled labor.

Well Support Services Outlook

We are encouraged by the operational and financial improvement achieved within our Well Support Services segment during the second quarter of 2018, and we currently expect that those underlying trends will continue over the remainder of the year, subject to the typical year end seasonal impact. We believe that higher oil prices and enhanced completion, workover and well maintenance economics should result in improved pricing, utilization and profitability. In our rig services business, we plan to allocate additional resources to customers with increasing workover activity and higher margin 24-hour completion-oriented work in key basins. In our fluids management business, we expect to allocate assets into areas with growing fluids logistics and disposal demand due to higher completion activity levels in areas such as the Mid-Continent and both West and South Texas. Additionally, late in the second quarter of 2018 we decided to shut-down our East Texas rig services operations and early in the third quarter of 2018, we made the decision to exit the condensate hauling business in California, which is in-line with our strategy of exiting unprofitable businesses and should help to improve our margins over the coming quarters. We anticipate that we will continue to experience skilled labor shortages in most of our operating basins and thus expect to continue increasing our rates commensurate with rising labor costs in order to recruit and retain skilled personnel. We are focused on further capitalizing on higher customer activity levels and we are maintaining our strategy of

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aligning with customers who have deep inventories of work and who value our ability to safely deliver superior service quality to continue increasing segment profitability and returns.

For additional information, please see “Liquidity and Capital Resources” and “Reportable Segments” in this Part I, Item 2 “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” in addition to “Cautionary Note Regarding Forward-Looking Statements” in Part I, Financial Information and “Risk Factors” in Part II, Item 1A of this Quarterly Report.

Results of Operations

The following is a comparison of our results of operations for the three and six months ended June 30, 2018 compared to the three and six months ended June 30, 2017. The results for the Predecessor on January 1, 2017 reflect solely the impact of the application of fresh start accounting on that date and are therefore not included in the discussion of results of operations below.

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Results for the Three Months Ended June 30, 2018 Compared to the Three Months Ended June 30, 2017

The following table summarizes the change in our results of operations for the three months ended June 30, 2018 when compared to the three months ended June 30, 2017 (in thousands):



	Three Months Ended June 30, 2018			Three Months Ended June 30, 2017			$ Change
Completion Services:
Revenue	$	412,895		$	262,880		$	150,015
Operating income	$	55,626		$	28,936		$	26,690

Well Construction and Intervention Services:
Revenue	$	99,086		$	31,267		$	67,819
Operating income (loss)	$	8,498		$	448		$	8,050

Well Support Services:
Revenue	$	98,540		$	95,996		$	2,544
Operating loss	$	(2,709	)	$	(7,608	)	$	4,899

Corporate / Elimination:
Revenue	$	—		$	—		$	—
Operating loss	$	(30,521	)	$	(35,020	)	$	4,499

Combined:
Revenue	$	610,521		$	390,143		$	220,378

Costs and expenses:
Direct costs	463,602			310,473			153,129
Selling, general and administrative expenses	59,908			61,165			(1,257		)
Research and development	1,681			2,052			(371		)
Depreciation and amortization	54,387			32,833			21,554
(Gain) loss on disposal of assets	49			(3,136		)	3,185
Operating income (loss)	30,894			(13,244		)	44,138
Other income (expense):
Interest expense, net	(2,185		)	(414		)	(1,771		)
Other income (expense), net	(1,106		)	(1,456		)	350
Total other income (expense)	(3,291		)	(1,870		)	(1,421		)
Income (loss) before income taxes	27,603			(15,114		)	42,717

Income tax benefit	(893		)	(2,393		)	1,500
Net income (loss)	$	28,496		$	(12,721	)	$	41,217

Revenue

Revenue increased $220.4 million, or 56.5%, to $610.5 million for the three months ended June 30, 2018, as compared to $390.1 million for the three months ended June 30, 2017. The increase in revenue was primarily due to (i) an increase of $150.0 million in our Completion Services segment as a result of our expanded fracturing services asset base, as well as improved utilization and pricing, (ii) an increase of $67.8 million in our Well Construction and Intervention Services segment as a result of (a) an increase in cementing revenue due to our expanded business with the acquisition of O-Tex Holdings, Inc. ("O-Tex") during the fourth quarter of 2017 and (b) growing market share, the deployment of additional units and higher utilization and pricing and (iii) an increase of $2.5 million in our Well Support Services segment as a result of

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improving utilization and pricing levels, partially offset by the divestiture of our Canadian rig services business in the fourth quarter of 2017.

Direct Costs

Direct costs increased $153.1 million, or 49.3%, to $463.6 million for the three months ended June 30, 2018, compared to $310.5 million for the three months ended June 30, 2017. The increase in direct costs was primarily due to the increased revenue across our segments. Revenue has been positively impacted by expanded asset bases, increased utilization and pricing levels and our expanded cementing business with the acquisition of O-Tex.

As a percentage of revenue, direct costs decreased to 75.9% for the three months ended June 30, 2018, as compared to 79.6% for the three months ended June 30, 2017. The decrease was primarily due to substantially improved pricing for our services due to the more favorable market conditions resulting from the increase in commodity prices as well as the divestiture of underperforming businesses and shutting down unprofitable districts.

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

SG&A decreased $1.3 million, or 2.1%, to $59.9 million for the three months ended June 30, 2018, as compared to $61.2 million for the three months ended June 30, 2017. The decrease in SG&A was primarily due to a $5.7 million decrease in restructuring charges related to our Chapter 11 bankruptcy proceeding in the corresponding prior year period, offset by (i) an incremental $2.7 million increase in SG&A expenses as a result of the acquisition of O-Tex and (ii) a $1.7 million increase in other general and administrative expenses.

Depreciation and Amortization Expense (“D&A”)

D&A increased $21.6 million, or 65.6%, to $54.4 million for the three months ended June 30, 2018, as compared to $32.8 million for the three months ended June 30, 2017. The increase in D&A was primarily the result of increased capital expenditures associated with equipment placed into service after the second quarter of 2017 and the integration of the acquired O-Tex asset base in the fourth quarter of 2017.

Interest Expense

Interest expense increased $1.8 million, or 427.8%, to $2.2 million for the three months ended June 30, 2018, as compared to $0.4 million for the three months ended June 30, 2017. The increase is primarily due to a $1.5 million non-cash deferred financing charge related to the previous credit facility.

Income Taxes

We recorded a tax benefit of $0.9 million for the three months ended June 30, 2018, at a negative effective rate of (3.2%), compared to a tax benefit of $2.4 million for the comparable prior year period, at an effective rate of 15.8%. The decrease in the effective tax rate, and the resulting effective tax rate below the expected statutory rate, was primarily due to the existence and adjustment of our valuation allowance applied against certain deferred tax assets, including net operating loss carryforwards.

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Results for the Six Months Ended June 30, 2018 Compared to the Six Months Ended June 30, 2017

The following table summarizes the change in our results of operations for the six months ended June 30, 2018 when compared to the six months ended June 30, 2017 (in thousands):



	Six Months Ended June 30, 2018			Six Months Ended June 30, 2017			$ Change
Completion Services:
Revenue	$	787,040		$	454,689		$	332,351
Operating income	$	113,934		$	40,280		$	73,654

Well Construction and Intervention Services:
Revenue	$	186,503		$	57,386		$	129,117
Operating income (loss)	$	13,955		$	(87	)	$	14,042

Well Support Services:
Revenue	$	189,978		$	192,262		$	(2,284	)
Operating loss	$	(11,251	)	$	(15,550	)	$	4,299

Corporate / Elimination:
Revenue	$	—		$	—		$	—
Operating loss	$	(65,402	)	$	(74,295	)	$	8,893

Combined:
Revenue	$	1,163,521		$	704,337		$	459,184

Costs and expenses:
Direct costs	882,599			572,216			310,383
Selling, general and administrative expenses	125,843			123,257			2,586
Research and development	3,553			3,269			284
Depreciation and amortization	100,730			64,439			36,291
Gain on disposal of assets	(440		)	(9,192		)	8,752
Operating income (loss)	51,236			(49,652		)	100,888
Other income (expense):
Interest expense, net	(2,613		)	(1,105		)	(1,508		)
Other income (expense), net	(486		)	106			(592		)
Total other income (expense)	(3,099		)	(999		)	(2,100		)
Income (loss) before income taxes	48,137			(50,651		)	98,788

Income tax benefit	(953		)	(5,629		)	4,676
Net income (loss)	$	49,090		$	(45,022	)	$	94,112

Revenue

Revenue increased $459.2 million, or 65.2%, to $1.2 billion for the six months ended June 30, 2018, as compared to $704.3 million for the six months ended June 30, 2017. The increase in revenue was primarily due to (i) an increase of $332.4 million in our Completion Services segment as a result of our expanded fracturing services asset base, as well as the strong demand for all of our completion services, which resulted in improved utilization and pricing, (ii) an increase of $129.1 million in our Well Construction and Intervention Services segment as a result of (a) an increase in cementing revenue due to our expanded business with the acquisition of O-Tex during the fourth quarter of 2017 and (b) growing market share, the deployment of additional units and higher utilization and pricing and (iii) a decrease of $2.3 million in our Well Support

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Services segment primarily as a result of the divestiture of our Canadian rig services business in the fourth quarter of 2017, partially offset by improving customer demand and pricing.

Direct Costs

Direct costs increased $310.4 million, or 54.2%, to $882.6 million for the six months ended June 30, 2018, compared to $572.2 million for the six months ended June 30, 2017. The increase in direct costs was primarily due to the increased revenue across our segments. Revenue has been positively impacted by expanded asset bases, increased utilization and pricing levels and our expanded cementing business with the acquisition of O-Tex.

As a percentage of revenue, direct costs decreased to 75.9% for the six months ended June 30, 2018, as compared to 81.2% for the six months ended June 30, 2017. The decrease was primarily due to substantially improved pricing for our services due to the more favorable market conditions resulting from the increase in commodity prices as well as the divestiture of underperforming businesses and shutting down unprofitable districts.

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

SG&A increased $2.6 million, or 2.1%, to $125.8 million for the six months ended June 30, 2018, as compared to $123.3 million for the six months ended June 30, 2017. The increase in SG&A was primarily due to (i) an incremental $5.5 million increase in SG&A expenses as a result of the acquisition of O-Tex, (ii) a $4.8 million increase in employee related costs (excluding O-Tex) due to the overall growth of our business, (iii) a $4.2 million increase in severance expense and accelerated equity vesting associated with the departure of an executive officer, (iv) a $1.4 million increase from the reinstatement of employer matching for an employee retirement plan and (v) a $2.4 million increase in other general and administrative expenses, offset by (i) a $10.8 million reduction in share based compensation expense related to an accelerated vesting in the first quarter of 2017 and (ii) a $4.9 million reduction in restructuring costs associated with the Chapter 11 proceeding in the corresponding prior year period.

Depreciation and Amortization Expense (“D&A”)

D&A increased $36.3 million, or 56.3%, to $100.7 million for the six months ended June 30, 2018, as compared to $64.4 million for the six months ended June 30, 2017. The increase in D&A was primarily the result of increased capital expenditures associated with equipment placed into service after the second quarter of 2017 and the integration of the acquired O-Tex asset base in the fourth quarter of 2017.

Interest Expense

Interest expense increased $1.5 million, or 136.5% to $2.6 million for the six months ended June 30, 2018, as compared to $1.1 million for the six months ended June 30, 2017. The increase was primarily due to a $1.5 million non-cash deferred financing charge related to the previous credit facility.

Income Taxes

We recorded a tax benefit of $1.0 million for the six months ended June 30, 2018, at a negative effective rate of (2.0%), compared to a tax benefit of $5.6 million for the comparable prior year period, at an effective rate of 11.1%. For the six months ended June 30, 2018, before the effect of additional allowed refund claims, we recorded income taxes at an estimated effective tax rate of approximately (1.8%). The decrease in the effective tax rate, and the resulting effective tax rate below the expected statutory rate, was primarily due to the existence, and adjustment of our valuation allowance applied against certain deferred tax assets, including net operating loss carryforwards.

Liquidity and Capital Resources

Sources of Liquidity and Capital Resources

Our primary uses of cash are for operating costs, capital expenditures and other expenditures. The oilfield services business is capital-intensive, requiring significant investment to maintain, upgrade and purchase equipment to meet our customers’ needs and industry demand. Our capital expenditures consist primarily of:

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•	growth capital expenditures, which are capital expenditures made to acquire additional equipment and other assets, increase our service lines, or advance other strategic initiatives for the purpose of growing our business; and


•	maintenance capital expenditures, which are capital expenditures related to our existing equipment, such as refurbishment and other activities to extend the useful life of partially or fully depreciated assets.

Our primary sources of liquidity have historically included, and we have funded our capital expenditures with, cash flows from operations, proceeds from public offerings of our common stock and borrowings under debt facilities. Our ability to generate future cash flows is subject to a number of variables, many of which are outside of our control, including the drilling, completion and production activity by our customers, which is highly dependent on oil and gas prices. See Part I, Item 2 “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Industry Trends and Outlook” for additional discussion of certain factors that impact our results and the market challenges within our industry. Please also read “-Financial Condition and Cash Flows” below for information about net cash provided by or used in our operating, investing and financing activities.

Through the first half of 2018, our financial performance and condition has remained strong, and we have maintained a strong balance sheet and a conservative capital structure. As of June 30, 2018, we had a cash balance of $110.0 million and no borrowings drawn on our Credit Facility, which had $356.4 million of available borrowing capacity after taking into consideration our current outstanding letters of credit of approximately $21.7 million. This resulted in total liquidity of $466.4 million as of June 30, 2018. As of August 6, 2018, we had a cash balance of approximately $78.7 million, no borrowings drawn on our Credit Facility, and letters of credit outstanding totaled $21.7 million, therefore $345.8 million of the Credit Facility was available, resulting in total liquidity of approximately $424.5 million. Under the terms of our Credit Facility, the borrowing base is subject to monthly adjustments based on current levels of accounts receivable and inventory. For additional information about the Credit Facility, please see “Description of our Indebtedness” below and Note 3 - Debt in Part I, Item 1 “Financial Statements” of this Quarterly Report.

Capital expenditures totaled $92.8 million in the second quarter of 2018, primarily pertaining to the maintenance of deployed equipment, the refurbishment of existing stacked equipment and related reactivation costs for redeployment primarily in the second quarter of 2018, and the building of new equipment for our Completion and Well Construction and Intervention Services segments. Based on current market conditions and revised assumptions on future customer demand, we currently expect our 2018 capital expenditure budget to range between $340.0 million and $355.0 million. The decrease from the initial estimation of $430.0 million to $450.0 million is due to our decision to delay reactivating our remaining stacked 120,000 HHP, as further explained below. The majority of our 2018 capital expenditure program is currently planned to be used for the refurbishment and reactivation of now redeployed frac fleets (the last of which was redeployed in July 2018), the refurbishment and redeployment of stacked equipment for most of our other core service lines, the manufacturing and deployment of select new-build equipment in our Completion and Well Construction and Intervention Services segments, and the ongoing maintenance of our active, deployed equipment across our asset base. However, if current market conditions change, we may further re-evaluate our current plan with respect to equipment reactivation and deployment.

During the first half of 2018, we allocated our capital budget largely to refurbishing and redeploying our previously stacked frac fleets. We redeployed two refurbished horizontal frac fleets during the second quarter of 2018 and one refurbished horizontal frac fleet early in the third quarter of 2018, as well as one new-build frac fleet consisting of new-build Tier II frac pumps in the first quarter of 2018. We also invested in equipment upgrades and standardization concurrent with our reactivation efforts, which among other benefits, is expected to increase the operating life of the equipment and lower the overall cost of ownership over time. Late in the second quarter of 2018, we began to experience weaker customer demand and lower utilization in our fracturing business, and on June 11, 2018, we issued a press release announcing our decision to delay the refurbishment and future redeployment of our remaining three stacked horizontal frac fleets consisting of approximately 120,000 HHP. The refurbishment of these last three fleets currently has an average estimated capital cost of approximately $27.0 million per 40,000 HHP horizontal (or horizontal equivalent) frac fleet inclusive of the pump refurbishment costs and the ancillary equipment necessary for reactivation. The estimated capital cost to redeploy the remainder of our stacked HHP is inherently uncertain until the refurbishment process begins. Although we believe that approximately $27.0 million per horizontal equivalent frac fleet on average is a reasonable estimate, the actual capital cost to redeploy the remainder of our stacked HHP may exceed our current estimates, particularly since the remaining fleets are expected to require more intensity due to their condition. Additionally, based on current market conditions, we have delayed certain amounts of both growth and maintenance capital spending in our other non-frac businesses based on revised expectations of near-term activity levels, all of which are included in the revised 2018 capital expenditure budget discussed above. If current market conditions change, we may further reevaluate our current plan with respect to equipment reactivation and deployment across all of our core service lines.

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We expect to fund our 2018 capital expenditure program primarily with cash flows from operations and potential borrowings under our Credit Facility. The amount of indebtedness we have outstanding at any time could limit our ability to finance future growth and could adversely affect our operations and financial condition. Based on our existing operating performance, we currently believe that our cash flows from operations, cash on hand and borrowings under our Credit Facility will be sufficient to meet our operational and capital expenditure requirements over the next twelve months.

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, 2018			Six Months Ended June 30, 2017
Cash provided by (used in):
Operating activities	$	134,727		$	(96,854	)
Investing activities	(133,428		)	(41,365		)
Financing activities	(5,337		)	210,587
Effect of exchange rate on cash	193			(855		)
Change in cash and cash equivalents	$	(3,845	)	$	71,513

Cash Provided by (Used in) Operating Activities

Net cash provided by operating activities was $134.7 million for the six months ended June 30, 2018. The inflow of cash was primarily related to net income of $49.1 million, adjustments for non-cash items of $114.6 million, $4.2 million related to a federal income tax refund and positive changes in other operating assets and liabilities primarily related to prepaid expenses and accounts payable. These cash inflows were offset by $75.5 million of increased investment in working capital (accounts receivable, inventory and payroll related costs and accrued expenses) as a result of the increase in demand for our services across all our segments for the first six months of 2018.

Net cash used in operating activities was $96.9 million for the six months ended June 30, 2017. The use of cash was primarily related to $166.6 million of increased investment in working capital (accounts receivable and inventory) as a result of the increase in the demand for our Completion Services and Well Construction and Intervention Services segments for the first six months of 2017 and a temporary increase in days sales outstanding as a result of our migration to the new ERP system. This cash outflow was partially offset by net loss of $45.0 million and adjustments for non-cash items of $77.0 million as well as positive changes in operating assets and liabilities, excluding accounts receivable and inventory.

Cash Used in Investing Activities

Net cash used in investing activities was $133.4 million for the six months ended June 30, 2018. The use of cash was related to $155.8 million of capital expenditures for the refurbishment of existing stacked equipment and the building of new equipment for our Completion and Well Construction and Intervention Services segments, offset by $20.9 million of proceeds from the disposal of property, plant and equipment and a $1.5 million refund from a working capital adjustment related to the O-Tex acquisition.

Net cash used in investing activities was $41.4 million for the six months ended June 30, 2017. The use of cash was related to $72.5 million of capital expenditures for the refurbishment of stacked equipment and the construction of new-build Frac pumps and refurbished ancillary equipment, offset by $27.1 million of proceeds from the divestiture of our non-core business lines previously reported under our Other Services reportable segment and $4.0 million of proceeds from the disposal of property, plant and equipment.

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Cash Provided by (Used in) Financing Activities

Net cash used in financing activities was $5.3 million for the six months ended June 30, 2018. The cash used was primarily related to $3.1 million of cash paid for financing costs related to our Credit Facility and $2.2 million of employee tax withholding on restricted stock vesting.

Net cash provided by financing activities was $210.6 million for the six months ended June 30, 2017. The cash provided was primarily related to $215.9 million of proceeds from the public offering of common stock, offset by $3.9 million of employee tax withholding on restricted stock vesting and $1.5 million of cash paid for financing costs related to our Prior Credit Facility.

Description of our Indebtedness

Current Credit Facility

The Company and certain of its subsidiaries (the “Borrowers”) entered into that certain Asset-Based Revolving Credit Agreement with, among others, JPMorgan Chase Bank, N.A., as administrative agent (the “Agent”), on May 1, 2018 (the "Credit Facility").

The Credit Facility allows the Borrowers to incur revolving loans in an aggregate amount up to the lesser of (a) $400.0 million or (b) a borrowing base (the “Loan Cap”), which borrowing base is based upon the value of the Borrowers’ accounts receivable, inventory and restricted cash, subject to eligibility criteria and customary reserves which may be modified in the Agent’s permitted discretion.

The Credit Facility also provides for the issuance of letters of credit, which would further reduce borrowing capacity thereunder. The maturity date of the Credit Facility is May 1, 2023.

At the Borrowers’ election, interest on borrowings under the Credit Facility will be determined by reference to either LIBOR plus an applicable margin of between 1.50% and 2.00% or an “alternate base rate” plus an applicable margin of between 0.50% and 1.00%, in each case based on the Company’s total leverage ratio. Interest will be payable quarterly for loans bearing interest based on the alternative base rate and on the last day of the interest period applicable to LIBOR-based loans and, in the case of an interest period longer than three months, quarterly, upon any prepayment and at final maturity. The Borrowers will also be required to pay a fee on the unused portion of the Credit Facility equal to (i) 0.50% per annum if average utilization is less than or equal to 25% or (ii) 0.375% per annum if average utilization is greater than 25%, in each case payable quarterly in arrears to the Agent.

The fixed charge coverage ratio is generally defined in the Credit Facility as the ratio of (i) EBITDA minus certain capital expenditures and cash taxes paid to (ii) the sum of cash interest expenses, scheduled principal payments on borrowed money and certain distributions.

Prior Credit Facility

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The Company and certain of its subsidiaries (the “Prior Borrowers”) entered into a credit facility on January 6, 2017, which was subsequently amended and restated in full on May 4, 2017 (the "Prior Credit Facility"). The Prior Credit Facility was canceled and discharged on May 1, 2018.

The Prior Credit Facility allowed the Prior Borrowers to incur revolving loans in an aggregate amount up to the lesser of (a) $200.0 million or (b) a borrowing base, which borrowing base was based upon the value of the Prior Borrowers’ accounts receivable and inventory, subject to eligibility criteria and customary reserves which may have been modified in the Prior Agent’s permitted discretion.

The Prior Credit Facility also provided for the issuance of letters of credit, which would further reduce borrowing capacity thereunder. The maturity date of the Prior Credit Facility was May 4, 2022.

At the Prior Borrowers’ election, interest on borrowings under the Prior Credit Facility would have been determined by reference to either LIBOR plus an applicable margin of 2.0% or an “alternate base rate” plus an applicable margin of 1.0%. Beginning after the fiscal month ending on or about September 30, 2017, these margins were subject to a monthly step-up of 0.25% in the event that average excess availability under the Prior Credit Facility was less than 37.5% of the total commitment, and a monthly step-down of 0.25% in the event that average excess availability under the Prior Credit Facility was equal to or greater than 62.5% of the total commitment. Interest was payable quarterly for loans bearing interest based on the alternative base rate and on the last day of the interest period applicable to LIBOR-based loans. The Prior Borrowers were required to pay a fee on the unused portion of the Prior Credit Facility equal to (i) 0.75% in the event that utilization was less than 25.0% of the total commitment, (ii) 0.50% in the event that utilization was equal to or greater than 25% of the total commitment but less than 50% of the total commitment and (iii) 0.375% in the event that utilization was equal to or greater than 50% of the total commitment.

The Prior Credit Facility also contained a financial covenant which required the Company to maintain a monthly minimum fixed charge coverage ratio of 1.0:1.0 if, as of any month-end, liquidity is less than $40.0 million.

The fixed charge coverage ratio was generally defined in the Prior Credit Facility as the ratio of (i) EBITDA minus certain capital expenditures and cash taxes paid to (ii)the sum of cash interest expenses, scheduled principal payments on borrowed money and certain distributions.

Other Matters

Contractual Obligations

Our contractual obligations at June 30, 2018, did not change materially from those disclosed in Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Contractual Obligations” of our 2017Annual Report.

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, 2018.

Recent Accounting Pronouncements

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In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) ("ASU 2016-02"). ASU No. 2016-02 seeks to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and by disclosing key information about leasing arrangements. Unlike current U.S. GAAP, which requires only capital leases to be recognized on the balance sheet, ASU No. 2016-02 will require both operating and finance leases to be recognized on the balance sheet. Additionally, the new guidance will require disclosures to help investors and other financial statement users better understand the amount, timing, and uncertainty of cash flows arising from leases, including qualitative and quantitative requirements. The amendments in ASU No. 2016-02 are effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years, and early application is permitted. We will adopt this new accounting standard on January 1, 2019. We are currently determining the impacts of the new standard on our consolidated financial statements. The approach includes performing a detailed review of our lease portfolio by evaluating our population of leased assets and designing and implementing new processes and controls.

In June 2016, the FASB issued ASU No. 2016-13, Financial Instruments-Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments (“ASU 2016-13”), which amends U.S. GAAP by introducing a new impairment model for financial instruments that is based on expected credit losses rather than incurred credit losses. The new impairment model applies to most financial assets, including trade accounts receivable. The amendments in ASU 2016-13 are effective for interim and annual reporting periods beginning after December 15, 2019, although it may be adopted one year earlier, and requires a modified retrospective transition approach. We are currently evaluating the impact this standard will have on our results of operations and financial position.

In October 2016, the FASB issued ASU No. 2016-16, Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other Than Inventory ("ASU 2016-16"), which requires an entity to recognize the income tax consequences of an intra-entity asset transfer, other than an intra-entity asset transfer of inventory, when the transfer occurs. The ASU is effective for the interim and annual reporting periods beginning after December 15, 2017, including interim periods within those fiscal years, and early application is permitted. We adopted this new accounting standard on January 1, 2018. We recognized a cumulative effect adjustment as a reduction to retained earnings of $13.2 million which occurred as a result of the Company's adoption of ASU 2016-16.

In January 2017, the FASB issued ASU No. 2017-04, Intangibles-Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment ("ASU 2017-04"), which establishes a one-step process for testing goodwill for a drop in value. This ASU is effective for the interim and annual reporting periods beginning after December 15, 2019 and early adoption is permitted. We early adopted this new accounting standard on January 1, 2018 and the adoption did not have an impact on our consolidated financial statements.

In February 2018, the FASB issued ASU No. 2018-02, Income Statement - Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income ("ASU 2018-02"), which allows for a reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the Tax Cuts and Jobs Act and requires certain disclosures about stranded tax effects. This ASU is effective for the interim and annual reporting periods beginning after December 15, 2019, and early adoption is permitted. We are currently evaluating the impact of this standard on our consolidated financial statements.

In March 2018, the FASB issued ASU No. 2018-05, Income Taxes (Topic 740): Amendments to SEC Paragraphs Pursuant to SEC Staff Accounting Bulletin No. 118, ("ASU 2018-05"), which provides guidance on accounting for the tax effects of the Tax Cuts and Jobs Act (the Tax Act) pursuant to Staff Accounting Bulletin No. 18, which allows companies to complete the accounting under ASC 740 within a one-year measurement period from the Tax Act enactment date. This standard is effective upon issuance. We are currently within the one-year measurement period and are in the process of accounting for the tax effects of the Tax Act.

In June 2018, the FASB issued ASU No. 2018-07, Compensation-Stock Compensation (Topic 718): Improvements to Nonemployee Share-Based Payment Accounting, ("ASU 2018-07"), which expands the scope of Topic 718 to include all share-based payment transactions for acquiring goods and services from nonemployees. This ASU is effective for the interim and annual reporting periods beginning after December 15, 2018, and early adoption is permitted. We are currently evaluating the impact of this standard on our consolidated financial statements.

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

As of June 30, 2018, 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 2017 Annual Report.

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

We maintain disclosure controls and procedures that are designed to provide reasonable assurance that the information required to be disclosed by us in our reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and that such information is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure.

As required by Rule 13a-15(b) under the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this Quarterly Report. 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, 2018.

Changes in Internal Controls Over Financial Reporting.

There were 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) during the quarterly period ended June 30, 2018, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II – OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

We are, and from time to time may be, subject to various legal proceedings and claims incidental to or arising in the ordinary course of our business. Our management does not presently expect the outcome of those matters that are presently known to the Company, individually or collectively, to have a material adverse effect on our consolidated financial condition or results of operations. Please also see Note 6 - Commitments and Contingencies - Litigation in Part I, Item 1 “Financial Statements” of this Quarterly Report.

U.S. Department of Justice Criminal Investigation into Pre-Merger Incident

There is a pending criminal investigation led by the Department of Justice in connection with a fatality that occurred at a facility we now own in Williston, North Dakota. The fatality occurred on October 3, 2014, prior to our acquisition of such facility and the ongoing business in connection with the Nabors Merger. We are cooperating fully with the investigation, and expect to continue to do so. At this time, we cannot predict the outcome of the investigation.

ITEM 1A. RISK FACTORS

In addition to the information set forth in this Quarterly Report, including under the section titled “Cautionary Note Regarding Forward-Looking Statements,” you should carefully consider the information set forth in Item 1A “Risk Factors” in our 2017 Annual Report, which is incorporated by reference herein, 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.

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

No equity securities of the Company were sold during the period covered by this Quarterly Report that were not registered under the Securities Act.

The following table summarizes share repurchase activity by the Company for the three months ended June 30, 2018:



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
April 1 - April 30	326	$	25.82	—	—
May 1 - May 31	—	$	—	—	—
June 1 - June 30	—	$	—	—	—

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

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

ITEM 5. OTHER INFORMATION

None.

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ITEM 6. EXHIBITS

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



Exhibit No.		Description of Exhibit.

2.1		Agreement and Plan of Merger, dated as of October 25, 2017, among C&J Energy Services, Inc., Caymus Merger Sub, Inc., O-Tex Holdings, Inc., O-Tex Sellers Representative LLC and the Stockholders set forth therein (Incorporated by reference to Exhibit 2.1 to the Registrant’s Current Report on Form 8-K filed on October 26, 2017 (File No. 001-38023)).
3.1		Amended and Restated Certificate of Incorporation of C&J Energy Services, Inc. (Incorporated by reference to Exhibit 3.1 to the Registrant’s Current Report on Form 8-K filed on January 6, 2017(File No. 000-55404)).
3.2		Amended and Restated Bylaws of C&J Energy Services, Inc. (Incorporated by reference to Exhibit 3.2 to the Registrant's Quarterly Report on Form 10-Q filed on November 9, 2017(File No. 001-38023)).
3.3		Certificate of Elimination of Series A Participating Cumulative Preferred Stock of C&J Energy Services, Inc. (Incorporated by reference to Exhibit 3.1 to the Registrant’s Current Report on Form 8-K filed on November 9, 2017 (File No. 001-38023)).
10.1		Asset-Based Revolving Credit Agreement, dated as of May 1, 2018, among C&J Energy Services, Inc., CJ Holding Co., C&J Spec-Rent Services, Inc., C&J Well Services, Inc., KVS Transportation, Inc., Tiger Cased Hole Services, Inc., each guarantor from time to time party hereto, each lender from time to time party hereto and JPMorgan Chase Bank, N.A., as the Administrative Agent (Incorporated by reference to Exhibit 10.1 to the Registrant's Current Report on Form 8-K filed on May 3, 2018 (File No. 001-38023)).
* 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.
+	Management contract or any compensatory plan, contract or arrangement.

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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 7, 2018	By:	/s/ Donald J. Gawick
			Donald J. Gawick
			Chief Executive Officer, President and Director
			(Principal Executive Officer)

		By:	/s/ Michael S. Galvan
			Michael S. Galvan
			Interim Chief Financial Officer and Chief Accounting Officer
			(Principal Financial Officer and Principal Accounting Officer)

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EXHIBIT INDEX



Exhibit No.		Description of Exhibit.

3.1		Amended and Restated Certificate of Incorporation of C&J Energy Services, Inc. (Incorporated by reference to Exhibit 3.1 to the Registrant’s Current Report on Form 8-K filed on January 6, 2017(File No. 000-55404)).
3.2		Amended and Restated Bylaws of C&J Energy Services, Inc. (Incorporated by reference to Exhibit 3.2 to the Registrant's Quarterly Report on Form 10-Q filed on November 9, 2017(File No. 001-38023)).
3.3		Certificate of Elimination of Series A Participating Cumulative Preferred Stock of C&J Energy Services, Inc. (Incorporated by reference to Exhibit 3.1 to the Registrant’s Current Report on Form 8-K filed on November 9, 2017 (File No. 001-38023)).
10.1		Asset-Based Revolving Credit Agreement, dated as of May 1, 2018, among C&J Energy Services, Inc., CJ Holding Co., C&J Spec-Rent Services, Inc., C&J Well Services, Inc., KVS Transportation, Inc., Tiger Cased Hole Services, Inc., each guarantor from time to time party hereto, each lender from time to time party hereto and JPMorgan Chase Bank, N.A., as the Administrative Agent (Incorporated by reference to Exhibit 10.1 to the Registrant's Current Report on Form 8-K filed on May 3, 2018 (File No. 001-38023)).
* 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.
+	Management contract or any compensatory plan, contract or arrangement.

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C&J Energy Services, Inc. - FORM 10-Q - August 7, 2018

Attached files

C&J Energy Services, Inc. Reports