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

Attached files

file	filename
EX-32.2 - EXHIBIT 32.2 - C&J Energy Services, Inc.	cjes063017ex322.htm
EX-32.1 - EXHIBIT 32.1 - C&J Energy Services, Inc.	cjes063017ex321.htm
EX-31.2 - EXHIBIT 31.2 - C&J Energy Services, Inc.	cjes063017ex312.htm
EX-31.1 - EXHIBIT 31.1 - C&J Energy Services, Inc.	cjes063017ex311.htm

Table of Contents

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, 2017



¨	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, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.



Large accelerated filer	¨	Accelerated filer	¨

Non-accelerated filer	ý (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 4, 2017, was 63,261,567.

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, 2017 (Successor) and December 31, 2016 (Predecessor)	1

	Consolidated Statements of Operations for the three months ended June 30, 2017 (Successor) and for the three months ended June 30, 2016 (Predecessor)	2

	Consolidated Statements of Operations for the six months ended June 30, 2017 (Successor), on January 1, 2017 (Predecessor) and for the six months ended June 30, 2016 (Predecessor)	3

	Consolidated Statements of Comprehensive Income (Loss) for the three and six months ended June 30, 2017 (Successor), on January 1, 2017 (Predecessor) and for the three and six months ended June 30, 2016 (Predecessor)	4

	Consolidated Statements of Changes in Stockholders' Equity for the year ended December 31, 2016 (Predecessor), on January 1, 2017 (Predecessor) and for the six months ended June 30, 2017 (Successor)	5

	Consolidated Statements of Cash Flows for the six months ended June 30, 2017 (Successor), on January 1, 2017 (Predecessor) and for the six months ended June 30, 2016 (Predecessor)	6

	Notes to Consolidated Financial Statements	7

	Cautionary Note Regarding Forward-Looking Statements	37

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	39

	Reportable Segments	41

	Operating Overview	45

	Results of Operations	48

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	58

Item 4.	Controls and Procedures	58

PART II – OTHER INFORMATION

Item 1.	Legal Proceedings	59

Item 1A.	Risk Factors	59

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	60

Item 3.	Defaults Upon Senior Securities	60

Item 4.	Mine Safety Disclosures	60

Item 5.	Other Information	60

Item 6.	Exhibits	61

	Signatures	62

-i-

Table of Contents

PART I – FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In thousands, except share data)



	Successor			Predecessor
	June 30, 2017			December 31, 2016
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	252,755		$	64,583
Accounts receivable, net of allowance of $2,012 at June 30, 2017 and $2,951 at December 31, 2016	294,877			137,084
Inventories, net	57,195			54,471
Prepaid and other current assets	44,591			37,611
Deferred tax assets	—			6,020
Total current assets	649,418			299,769
Property, plant and equipment, net of accumulated depreciation of $62,260 at June 30, 2017 and $683,189 at December 31, 2016	588,285			950,811
Other assets:
Intangible assets, net	54,617			76,057
Deferred financing costs	3,405			—
Other noncurrent assets	41,122			35,045
Total assets	$	1,336,847		$	1,361,682
LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT)
Current liabilities:
Accounts payable	$	112,131		$	74,382
Payroll and related costs	28,153			17,991
Accrued expenses	56,143			60,363
DIP Facility	—			25,000
Other current liabilities	1,245			2,980
Total current liabilities	197,672			180,716
Deferred tax liabilities	4,910			15,613
Other long-term liabilities	22,136			18,577
Total liabilities not subject to compromise	224,718			214,906
Liabilities subject to compromise	—			1,445,346
Commitments and contingencies
Stockholders' equity:
Predecessor common shares, par value of $0.01, 750,000,000 shares authorized, 119,529,942 issued and outstanding at December 31, 2016	—			1,195
Predecessor additional paid-in capital	—			1,009,426
Predecessor accumulated other comprehensive loss	—			(2,600		)
Successor common stock, par value of $0.01, 1,000,000,000 shares authorized, 63,265,085 issued and outstanding at June 30, 2017	633			—
Successor additional paid-in capital	1,156,822			—
Successor accumulated other comprehensive loss	(304		)	—
Retained deficit	(45,022		)	(1,306,591		)
Total stockholders' equity (deficit)	1,112,129			(298,570		)
Total liabilities and stockholders’ equity (deficit)	$	1,336,847		$	1,361,682

See accompanying notes to consolidated financial statements

-1-

Table of Contents

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per share data)

(Unaudited)



	Successor			Predecessor
	Three Months Ended June 30, 2017			Three Months Ended June 30, 2016
Revenue	$	390,143		$	225,168
Costs and expenses:
Direct costs	310,473			229,771
Selling, general and administrative expenses	61,165			71,341
Research and development	2,052			1,786
Depreciation and amortization	32,833			54,283
Impairment expense	—			48,712
(Gain) loss on disposal of assets	(3,136		)	1,712
Operating loss	(13,244		)	(182,437		)
Other income (expense):
Interest expense, net	(414		)	(121,934		)
Other income (expense), net	(1,456		)	2,003
Total other income (expense)	(1,870		)	(119,931		)

Loss before income taxes	(15,114		)	(302,368		)
Income tax benefit	(2,393		)	(11,252		)

Net loss	$	(12,721	)	$	(291,116	)
Net loss per common share:
Basic	$	(0.20	)	$	(2.46	)
Diluted	$	(0.20	)	$	(2.46	)
Weighted average common shares outstanding:
Basic	62,232			118,426
Diluted	62,232			118,426

See accompanying notes to consolidated financial statements

-2-

Table of Contents

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per share data)

(Unaudited)



	Successor			Predecessor
	Six Months Ended June 30, 2017			On January 1, 2017			Six Months Ended June 30, 2016
Revenue	$	704,337		$	—		$	494,783
Costs and expenses:
Direct costs	572,216			—			491,536
Selling, general and administrative expenses	123,257			—			133,380
Research and development	3,269			—			4,163
Depreciation and amortization	64,439			—			113,236
Impairment expense	—			—			430,406
(Gain) loss on disposal of assets	(9,192		)	—			4,914
Operating income (loss)	(49,652		)	—			(682,852		)
Other income (expense):
Interest expense, net	(1,105		)	—			(147,401		)
Other income (expense), net	106			—			5,325
Total other income (expense)	(999		)	—			(142,076		)

Income (loss) before reorganization items and income taxes	(50,651		)	—			(824,928		)
Reorganization items	—			(293,969		)	—
Income tax benefit	(5,629		)	(4,613		)	(105,399		)

Net income (loss)	$	(45,022	)	$	298,582		$	(719,529	)
Net income (loss) per common share:
Basic	$	(0.76	)	$	2.52		$	(6.10	)
Diluted	$	(0.76	)	$	2.52		$	(6.10	)
Weighted average common shares outstanding:
Basic	58,913			118,633			117,979
Diluted	58,913			118,633			117,979

See accompanying notes to consolidated financial statements

-3-

Table of Contents

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(In thousands)

(Unaudited)



	Successor			Predecessor
	Three Months Ended June 30, 2017			Three Months Ended June 30, 2016
Net loss	$	(12,721	)	$	(291,116	)

Other comprehensive income (loss):
Foreign currency translation gain, net of tax	409			49
Comprehensive loss	$	(12,312	)	$	(291,067	)



	Successor			Predecessor
	Six Months Ended June 30, 2017			On January 1, 2017		Six Months Ended June 30, 2016
Net income (loss)	$	(45,022	)	$	298,582	$	(719,529	)

Other comprehensive income (loss):
Foreign currency translation gain (loss), net of tax	(304		)	—		2,023
Comprehensive income (loss)	$	(45,326	)	$	298,582	$	(717,506	)

See accompanying notes to consolidated financial statements

-4-

Table of Contents

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, 2015 (Predecessor)	120,420		$	1,204		$	997,766		$	(4,025	)	$	(362,302	)	$	632,643
Forfeitures of restricted shares	(576	)	(6		)	6			—			—			—
Employee tax withholding on restricted shares vesting	(314	)	(3		)	(494		)	—			—			(497		)
Tax effect of share-based compensation	—		—			(5,592		)	—			—			(5,592		)
Share-based compensation	—		—			17,740			—			—			17,740
Net loss	—		—			—			—			(944,289		)	(944,289		)
Foreign currency translation gain, net of tax	—		—			—			1,425			—			1,425
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 restricted stock, net of forfeitures	856		8			(8		)	—			—			—
Exercise of warrants	2		—			—			—			—			—
Employee tax withholding on restricted stock vesting	(107	)	(1		)	(3,869		)	—			—			(3,870		)
Share-based compensation	—		—			19,541			—			—			19,541
Net loss	—		—			—			—			(45,022		)	(45,022		)
Foreign currency translation loss, net of tax	—		—			—			(304		)	—			(304		)
Balance, June 30, 2017 (Successor) *	63,265		$	633		$	1,156,822		$	(304	)	$	(45,022	)	$	1,112,129



*	Unaudited

See accompanying notes to consolidated financial statements

-5-

Table of Contents

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)



	Successor			Predecessor
	Six Months Ended June 30, 2017			On January 1, 2017			Six Months Ended June 30, 2016
Cash flows from operating activities:
Net income (loss)	$	(45,022	)	$	298,582		$	(719,529	)
Adjustments to reconcile net income (loss) to net cash used in operating activities:
Depreciation and amortization	64,439			—			113,236
Impairment expense	—			—			430,406
Inventory write-down	—			—			13,047
Deferred income taxes	—			(4,613		)	(105,399		)
Provision for doubtful accounts	2,032			—			973
Equity in (earnings) losses from unconsolidated affiliate	(153		)	—			4,501
(Gain) loss on disposal of assets	(9,192		)	—			4,914
Share-based compensation expense	19,541			—			13,167
Amortization of deferred financing costs	306			—			48,309
Accretion of original issue discount	—			—			52,413
Reorganization items, net	—			(315,626		)	—
Changes in operating assets and liabilities:
Accounts receivable	(159,643		)	—			150,931
Inventory	(6,978		)	—			3,169
Prepaid and other current assets	6,741			—			14,952
Accounts payable	27,784			—			(121,847		)
Payroll and related costs and accrued expenses	6,747			(1,436		)	25,209
Liabilities subject to compromise	—			(33,000		)	—
Income taxes payable	(5,200		)	—			5,442
Other	1,744			—			(9,914		)
Net cash used in operating activities	(96,854		)	(56,093		)	(76,020		)
Cash flows from investing activities:
Purchases of and deposits on property, plant and equipment	(72,547		)	—			(36,437		)
Proceeds from disposal of property, plant and equipment	4,039			—			28,753
Investment in unconsolidated affiliate	—			—			(408		)
Proceeds from divestiture of non-core service lines	27,143			—			—
Payments made for business acquisitions, net of cash acquired	—			—			(1,419		)
Net cash used in investing activities	(41,365		)	—			(9,511		)
Cash flows from financing activities:
Proceeds from revolving debt	—			—			174,000
Payments on revolving debt	—			—			(10,600		)
Payments on term loans	—			—			(2,650		)
Payments on DIP Facility	—			(25,000		)	—
Payments of capital lease obligations	—			—			(1,520		)
Financing costs	(1,463		)	(2,248		)	—
Proceeds from public offering of common stock, net of offering costs	215,920			—			—
Proceeds from issuance of common stock from Rights Offering	—			200,000			—
Employee tax withholding on restricted stock vesting	(3,870		)	—			(434		)
Excess tax expense from share-based compensation	—			—			(5,592		)
Net cash provided by financing activities	210,587			172,752			153,204

Effect of exchange rate changes on cash	(855		)	—			(2,803		)

Net increase in cash and cash equivalents	71,513			116,659			64,870
Cash and cash equivalents, beginning of period	181,242			64,583			25,900
Cash and cash equivalents, end of period	$	252,755		$	181,242		$	90,770

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, “C&J” or the “Company”), is a leading provider of well construction, well completion, well support and other complementary oilfield services to oil and gas exploration and production companies in North America. The Company offers a comprehensive, vertically-integrated suite of services throughout the life cycle of the well, including fracturing, cased-hole wireline and pumping, cementing, coiled tubing, directional drilling, rig services, fluids management and other support services. The Company is headquartered in Houston, Texas and operates in all active onshore basins in the continental United States and Western Canada.

C&J’s business was founded in Texas in 1997 as a partnership and converted to a Delaware corporation (“Old C&J”) in 2010 in connection with an initial public offering that was completed in 2011 with a listing on the New York Stock Exchange (“NYSE”) under the symbol “CJES.” In 2015, Old C&J combined with the completion and production services business (the “C&P Business”) of Nabors Industries Ltd. (“Nabors”) in a transaction (the “Nabors Merger”) that nearly tripled the Company’s size, significantly expanding the Company’s Completion Services businesses and adding the Well Support Services businesses to the Company’s service offerings. Upon the closing of the Nabors Merger, Old C&J became a subsidiary of C&J Energy Services Ltd., a Bermuda corporation (the “Predecessor” and together with its subsidiaries and for periods prior to the Plan Effective Date, the “Predecessor Companies,” or the “Company”), and shares of common stock of Old C&J were converted into common shares of the Predecessor on a 1-for-1 basis.

Due to the severe industry downturn, on the Petition Date, certain of the Predecessor Companies filed voluntary petitions for reorganization seeking relief under the provisions of Chapter 11 of the United States Bankruptcy Code with the United States Bankruptcy Court in the Southern District of Texas, Houston Division. Certain of the Predecessor Companies also commenced ancillary proceedings in Canada and a provisional liquidation proceeding in Bermuda. 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.

On the Plan Effective Date, the Debtors substantially consummated their 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. 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.

Contemporaneously with the commencement of the Chapter 11 Proceeding, trading in the Predecessor’s common stock was suspended and ultimately delisted from the NYSE. On April 12, 2017, the Successor completed an underwritten public offering of common stock, and its common stock began trading again on the 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, 2016 and the consolidated statement of changes in stockholders' equity as of December 31, 2016, 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 year ended December 31, 2016, which are

-7-

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

included in the Company’s Annual Report on Form 10-K 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.

From the Petition Date through December 31, 2016, and on January 1, 2017 (the "Fresh Start Reporting Date"), the Company applied the 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 of the Predecessor. In addition, pre-petition obligations that management predicted might be impacted by the Chapter 11 Proceeding were classified on the balance sheet of the Predecessor in liabilities subject to compromise. These liabilities were reported at the amounts expected to be allowed by the Bankruptcy Court, even if they may be settled for lesser amounts.

Use of Estimates. The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenue and expenses during the reporting period. Estimates are used in, but are not limited to, determining the following: allowance for doubtful accounts, valuation of long-lived assets and intangibles, useful lives used in depreciation and amortization, inventory reserves, income taxes, liabilities subject to compromise and estimated fair values of assets and liabilities under the provisions of ASC 852 fresh start accounting ("Fresh Start"). 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 $13.7 million and $16.1 million at June 30, 2017 and December 31, 2016, 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 operations of the captive insurance subsidiaries.

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 for the Completion Services segment consist of finished goods, including equipment components, chemicals, proppants, supplies and materials for the segment’s operations. Inventories for the Other Services segment consisted of raw materials, work-in-process and finished goods, including equipment components, supplies and materials.

Consistent with FASB requirements under ASC 852, an entity adopting fresh-start accounting may generally set new accounting policies for the successor independent of those followed by the predecessor. The entity emerging from bankruptcy typically is not required to demonstrate preferability for its new accounting policies, as the successor entity represents a new entity for financial reporting purposes.

During January 2017, the Company implemented a new computer system that provides financial reporting, inventory management and fixed asset management capabilities (the "new ERP system") to enhance functionality and to support to Company's existing and future operations. The new ERP system utilizes the weighted average cost flow method for determining inventory cost ("Weighted Average"), which replaced the first-in, first-out basis ("FIFO") method utilized by the Predecessor's legacy system. The Weighted Average and FIFO methods are both allowable under U.S. GAAP. As of the Fresh Start Reporting Date, the Company began utilizing the Weighted Average method for determining inventory cost. Inventory cost for the prior periods presented are still reflective of the FIFO method.

Inventories consisted of the following (in thousands):

-8-

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)



	Successor			Predecessor
	June 30, 2017			December 31, 2016
Raw materials	$	6,956		$	16,367
Work-in-process	451			5,022
Finished goods	51,230			38,091
Total inventory	58,637			59,480
Inventory reserve	(1,442		)	(5,009		)
Inventory, net	$	57,195		$	54,471

Property, Plant and Equipment. Property, plant and equipment (“PP&E”) expenditures 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, 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 at the service line level, which consists of the well services, fracturing, wireline, pumping, cementing, coiled tubing, directional drilling, artificial lift applications and data acquisition and control instruments provider service lines as well as the research and technology ("R&T") service line. 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.

The Company concluded that the sharp fall in commodity prices during the second half of 2014 constituted a triggering event that resulted in a significant slowdown in activity across the Company’s customer base, which in turn increased competition and put pressure on pricing for its services throughout 2015 and 2016. Although uncertainty as to the severity and extent of this downturn still exists, activity and pricing levels may decline again in future periods. As a result of the triggering event during the fourth quarter of 2014, PP&E recoverability testing was performed throughout 2015 and 2016 on the asset groups in each of the Company’s service lines. For the first six months of 2016, the recoverability testing for the cementing, coiled tubing, directional drilling, artificial lift applications and international coiled tubing asset groups yielded an estimated undiscounted net cash flow that was less than the carrying amount of the related assets. The estimated fair value for each respective asset group was compared to its carrying value, and impairment expense of $61.1 million was recognized during the first half of 2016 and allocated across each respective asset group's major classification. The impairment charge was primarily related to underutilized equipment in the Completion Services and Other Services segments. The fair value of these assets was based on the projected present value of future cash flows that these assets are expected to generate. Should industry conditions worsen, additional impairment charges may be required in future periods. No impairment expense was recorded for the six months ended June 30, 2017.

Goodwill and Definite-Lived Intangible Assets. Prior to December 31, 2016, the Company allocated goodwill across the Completion Services, Well Support Services and Other Services reporting units, all of which were consistent with the presentation of the Company’s three reportable segments as of December 31, 2016.

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. During the first quarter of 2016, commodity price levels remained depressed which materially and negatively impacted the Company's results of operations, and the significant declines in the Company's share price led to an interim period test for goodwill impairment. See Note 5 - Goodwill and Other Intangible Assets for further discussion on impairment testing results.

-9-

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Before employing detailed 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, detailed testing methodologies are then applied. Otherwise, the Company concludes that no impairment has occurred.

Definite-lived intangible assets are amortized over their estimated useful lives. Along with PP&E, these intangibles are reviewed for impairment when a triggering event indicates that the asset 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.

For further discussion of the application of this accounting policy regarding impairments, please see Note 5 - Goodwill and Other Intangible Assets.

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 presented on the balance sheet as other assets and amortized over the term of the loan using the effective interest method.

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

Completion Services Segment

Fracturing Services Revenue. Through its fracturing business, the Company provides fracturing services on a spot market basis or pursuant to contractual arrangements, such as term contracts and pricing agreements. Under either scenario, revenue is recognized and customers are invoiced upon the completion of each job, which can consist of one or more fracturing stages. Once a job has been completed to the customer’s satisfaction, a field ticket is written that includes charges for the services performed and the consumables (such as fluids and proppants) 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.

Rates for services performed on a spot market basis are based on an agreed-upon hourly spot market rate for a specified number of hours of service.

Pursuant to pricing agreements and other contractual arrangements that the Company may enter into from time to time, such as those associated with an award from a bid process, customers typically commit to targeted utilization levels based on a specified number of hours of service at agreed-upon pricing, but without termination penalties or 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.

Casedhole Solutions Services Revenue. Through its Casedhole Solutions Services business, the Company provides cased-hole wireline, pumping, wireline logging, perforating, well site make-up and pressure testing and other complementary services, 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.

Well Construction & Intervention Services Revenue. Through its well construction and intervention services business, the Company provides cementing, coiled tubing and directional drilling services.

With respect to its cementing services, the Company provides these 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

-10-

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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 (such as blended bulk cement and chemical additives) used during the course of service.

With respect to its coiled tubing services, the Company provides a range of coiled tubing services primarily used for frac 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 (such as stimulation fluids, nitrogen and coiled tubing materials) 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.

With respect to its directional drilling services, the Company provides these services on a spot market basis. Jobs for these services are typically short-term in nature, lasting anywhere from a few days to multiple weeks. The Company typically charges 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 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.

Revenue from Materials Consumed While Performing Certain Completion Services. The Company generates revenue from consumables used during the course of providing services.

With respect to fracturing services, the Company generates revenue from the fluids, proppants and other materials that are consumed while performing a job. For services performed on a spot market basis, the required consumables are typically provided by the Company and the customer is billed for those consumables at cost plus an agreed-upon markup. For services performed on a contractual basis, when the consumables are provided by the Company, the customer typically is billed for those consumables at a negotiated contractual rate. When consumables are supplied by the customer, the Company typically charges handling fees based on the amount of consumables used.

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. Revenue is recognized upon the completion, delivery and customer acceptance of each order of parts and components.

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 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.

-11-

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

With respect to its artificial lift applications, the Company generates revenue primarily from the sale of manufactured equipment and products. Revenue is recognized upon the completion, delivery and customer acceptance of each order.

Other Services Segment

Revenue within the Other Services Segment was generated from certain of the Company’s smaller, non-core service lines that were divested in 2016, such as the Company's specialty chemical business, equipment manufacturing and repair business and international coiled tubing operations in the Middle East. In line with the discontinuance of these small, ancillary service lines and divisions, subsequent to the year ended December 31, 2016, the Company is now disclosing only two reportable segments, and financial information for the Other Services reportable segment is only presented for the corresponding prior year period.

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, 2017, only nonqualified stock options and restricted stock had been granted under such plan. The Company values option grants based on the grant date fair value by using the Black-Scholes option-pricing model and values restricted stock grants based on the closing price of C&J’s common stock on the grant date. 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 6 - 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 our 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 we recognize 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 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.

The Company has federal, state and international net operating losses (NOLs) carried forward from prior years that will expire in the years 2021 through 2036. 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.

-12-

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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 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. For the six months ended June 30, 2017, the Company recorded an income tax benefit of $3.3 million related to a decrease in the estimate of unrecognized tax benefits relating to uncertain tax positions. The decrease resulted primarily from the effect of changes in the application of relevant withholding tax provisions under applicable local country treaties related to certain of the Company's foreign subsidiaries. As of June 30, 2017, the remaining amount of unrecognized tax benefits relating to uncertain tax positions was $3.3 million.

Earnings (Loss) Per Share. Basic earnings (loss) per share is based on the weighted average number of shares of common stock outstanding during the applicable period and excludes shares subject to outstanding stock options and restricted stock. Diluted earnings per share is computed based on the weighted average number of shares of common stock 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:



	Successor			Predecessor
	Three Months Ended June 30, 2017			Three Months Ended June 30, 2016
	(In thousands, except per share amounts)			(In thousands, except per share amounts)
Numerator:
Net loss attributed to common stockholders	$	(12,721	)	$	(291,116	)
Denominator:
Weighted average common shares outstanding	62,232			118,426
Effect of potentially dilutive common shares:
Stock options	—			—
Restricted shares	—			—
Weighted average common shares outstanding and assumed conversions	62,232			118,426
Loss per common share:
Basic	$	(0.20	)	$	(2.46	)
Diluted	$	(0.20	)	$	(2.46	)

-13-

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)



	Successor			Predecessor
	Six Months Ended June 30, 2017			On January 1, 2017		Six Months Ended June 30, 2016
	(In thousands, except per share amounts)			(In thousands, except per share amounts)
Numerator:
Net income (loss) attributed to common stockholders	$	(45,022	)	$	298,582	$	(719,529	)
Denominator:
Weighted average common shares outstanding	58,913			118,633		117,979
Effect of potentially dilutive common shares:
Stock options	—			—		—
Restricted shares	—			—		—
Weighted average common shares outstanding and assumed conversions	58,913			118,633		117,979
Income (loss) per common share:
Basic	$	(0.76	)	$	2.52	$	(6.10	)
Diluted	$	(0.76	)	$	2.52	$	(6.10	)

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



	Successor	Predecessor
	Three Months Ended June 30, 2017	Three Months Ended June 30, 2016
	(In thousands)	(In thousands)
Basic loss per share:
Restricted shares	572	1,508
Diluted loss per share:
Anti-dilutive stock options	256	5,079
Anti-dilutive restricted shares	556	1,508
Potentially dilutive securities excluded as anti-dilutive	812	6,587



	Successor	Predecessor
	Six Months Ended June 30, 2017	On January 1, 2017	Six Months Ended June 30, 2016
	(In thousands)	(In thousands)
Basic loss per share:
Restricted shares	436	898	2,117
Diluted loss per share:
Anti-dilutive stock options	205	4,416	4,801
Anti-dilutive restricted shares	427	898	2,101
Potentially dilutive securities excluded as anti-dilutive	632	5,314	6,902

Recent Accounting Pronouncements. In May 2014, the Financial Accounting Standards Board ("FASB") issued a comprehensive new revenue recognition standard, Accounting Standards Update ("ASU") No. 2014-09, Revenue from Contracts with Customers ("ASU 2014-09") that will supersede existing revenue recognition guidance under U.S. GAAP. In August 2015, the FASB issued an accounting standards update for a one-year deferral of the revenue recognition standard's effective date for all entities, which changed the effectiveness to annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. The core principle of the new guidance is that a company should

-14-

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. The standard creates a five-step model that requires companies to exercise judgment when considering the terms of a contract and all relevant facts and circumstances. The standard allows for the following transition methods: (a) a full retrospective adoption in which the standard is applied to all of the periods presented, or (b) a modified retrospective adoption in which the standard is applied only to the most current period presented in the financial statements, including additional disclosures of the standard’s application impact to individual financial statement line items. The Company will adopt this new accounting standard on January 1, 2018, and upon adoption, the Company will incorporate the modified retrospective approach as its transition method that will result in a cumulative effect adjustment as of January 1, 2018. The Company is currently determining the impacts of the new standard on its contract portfolio. The approach includes performing a detailed review of key contracts representative of the Company’s different businesses and comparing historical accounting policies and practices to the new standard. The Company’s services are primarily short-term in nature, and the assessment at this stage is that the Company does not expect the new revenue recognition standard will have a material impact on the consolidated financial statements upon adoption.

In July 2015, the FASB issued ASU No. 2015-11, Simplifying the Measurement of Inventory ("ASU 2015-11"), which changes the measurement principle for inventory from the lower of cost or market to lower of cost and net realizable value. ASU 2015-11 is part of the FASB’s simplification initiative and applies to entities that measure inventory using a method other than last-in, first-out ("LIFO") or the retail inventory method. The guidance will require prospective application at the beginning of the Company's first quarter of fiscal 2018, but permits adoption in an earlier period. The Company does not expect this ASU to have a material impact on its consolidated financial statements.

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. The Company is currently evaluating the impact of adopting this new accounting standard on its results of operations and financial position.

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 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. The Company is currently evaluating the impact of adopting this new accounting standard on its results of operations and financial position.

Note 2 - Chapter 11 Proceeding and Emergence

Overview

On July 8, 2016, 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 Agreement”). The Restructuring Support Agreement contemplated the implementation of a financial restructuring of the Company, including the elimination of all amounts owed

-15-

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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 Debtor's plan of reorganization (the “Restructuring Plan”) under Chapter 11 of the U.S. Bankruptcy Code (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. 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 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.

The key terms of the restructuring included in the Restructuring Plan were as follows:


•	Debt-to-equity Conversion: As of the Plan Effective Date, the Supporting Lenders were issued new common equity (“New Equity”) in the Successor, as the ultimate parent company of the reorganized Debtors, and all of the existing shares of the Predecessor's common equity were canceled.

•

The Rights Offering, Backstop Commitment: The Company offered its secured lenders the right to purchase New Equity in an amount of up to $200.0 million as part of the approved Restructuring Plan (the “Rights Offering”). Certain of the Supporting Lenders (the “Backstop Parties”) agreed to backstop the full amount pursuant to a Backstop Commitment Agreement, in exchange for a commitment premium of 5.0% of the $200.0 million committed amount payable in New Equity to the Backstop Parties (the “Backstop Fee”). The Rights Offering was consummated on the Plan Effective Date and the shares were issued at a price that reflects a discount of 20.0% to the Restructuring Plan value, which was $750.0 million.

•

DIP Facility: Certain of the Supporting Lenders (the “DIP Lenders”) provided a superpriority secured delayed draw term loan facility to the Predecessor in an aggregate principal amount of up to $100.0 million (the “DIP Facility”). As further discussed below, on July 25, 2016, the Bankruptcy Court entered an order approving the Debtors’ entry into the DIP Facility on an interim basis, pending a final hearing. On July 29, 2016, the Debtors entered into a superpriority secured debtor-in-possession credit agreement, among the Debtors, the DIP Lenders and Cortland Capital Market Services LLC, as Administrative Agent (the “DIP Credit Agreement”), which set forth the terms and conditions of the DIP Facility. On September 25, 2016, the Bankruptcy Court entered a final order approving entry into the DIP Facility and DIP Credit Agreement. The Company repaid all amounts outstanding under the DIP Facility on the Plan Effective Date using proceeds from the Rights Offering.

•

The New Credit Facility: The Successor and certain of its subsidiaries, as borrowers (the “Borrowers”), entered into a revolving credit and security agreement (the “New Credit Facility”) dated the Plan Effective Date with a maturity date of January 6, 2021, with PNC Bank, National Association, as administrative agent (the “Agent”). The Borrowers subsequently amended and restated the New Credit Facility in full pursuant to an amended and restated credit and security agreement (the “Amended Credit Facility”) dated May 4, 2017, with the Agent and the lenders party thereto. The Amended Credit Facility allows the Borrowers to

-16-

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

incur revolving loans in an aggregate amount up to the lesser of $200.0 million and a borrowing base, which borrowing base is based upon the value of the Borrowers’ accounts receivable and inventory. The Amended Credit Facility also provides for the issuance of letters of credit, which would reduce borrowing capacity thereunder. The maturity date of the Amended Credit Facility is May 4, 2022.

•

The New Warrants: As of the Plan Effective Date, the Company agreed to issue new seven-year warrants exercisable on a net-share settled basis into up to 6.0% of the New Equity at a strike price of $27.95 per warrant (the “New Warrants”). New Warrants representing up to 2.0% of the New Equity were issued to existing holders of Predecessor common equity as a result of such holders voting as a class to accept the Restructuring Plan, and the remaining New Warrants representing up to 4.0% of the New Equity will be issued to the representative for the Debtors' general unsecured creditors.

•

Distributions: The DIP Lenders received payment in full in cash on the Plan Effective Date from cash on hand and proceeds from the Rights Offering. The Supporting Lenders received all of the New Equity, subject to dilution on account of the Management Incentive Plan (as defined below), the Rights Offering, the Backstop Fee and the New Warrants, along with all of the subscription rights under the Rights Offering. Under the Restructuring Plan, mineral contractor claimants have or will be paid in full in the ordinary course of business. Additionally, subject to the terms of the Restructuring Plan, certain other unsecured claimants will share in a $33.0 million cash recovery pool, plus a portion of the New Warrants, as described above.


•	Management Incentive Plan: 10.0% of the New Equity was reserved for a management incentive program to be issued to management of the Company after the Plan Effective Date from time to time at the discretion of the board of the reorganized Company (the “Management Incentive Plan”).


•	Governance: The board of the Successor was appointed by the Supporting Lenders and includes the Successor's Chief Executive Officer.

Liabilities Subject to Compromise

As of December 31, 2016, the Company had segregated liabilities and obligations whose treatment and satisfaction were dependent on the outcome of its reorganization under the Chapter 11 Proceeding and had classified these items as liabilities subject to compromise. Generally, all actions to enforce or otherwise effect repayment of pre-petition liabilities of the Debtors, as well as all pending litigation against the Debtors, were stayed while the Company was subject to the Chapter 11 Proceeding. Liabilities subject to compromise includes only those liabilities that are obligations of the Debtors and excludes the obligations of the Predecessor's non-debtor subsidiaries.

Principal and accrued interest owed to the Supporting Lenders as of the Petition Date were settled via the issuance of New Equity under the Restructuring Plan. Interest expense incurred subsequent to the Petition Date was not accrued since it was not treated as an allowed claim under the Restructuring Plan. For the year ended December 31, 2016, the Company did not accrue interest totaling $60.5 million under the Credit Agreement subsequent to the Petition Date.

As of December 31, 2016, the Company classified the entire principal balance of the Revolving Credit Facility, the Five-Year Term Loans and the Seven-Year Term Loans (see Note 4 - Debt for defined terms), as well as interest that was accrued but unpaid as of the Petition Date, as liabilities subject to compromise in accordance with ASC 852. The components of liabilities subject to compromise were as follows (in thousands):

-17-

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)



	December 31, 2016
Revolving Credit Facility	$	284,400
Five-Year Term Loans	569,250
Seven-Year Term Loans	480,150
Total debt subject to compromise	1,333,800
Accrued interest on debt subject to compromise	37,516
Accounts payable and other estimated allowed claims	60,780
Related party payables	13,250
Total liabilities subject to compromise	$	1,445,346

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 effectively complete, certain administrative activities will continue under the authority of the Bankruptcy Court for the next several months.

Note 3 - Fresh Start Accounting

The Company adopted Fresh Start accounting on the Plan Effective Date in connection with the Company's emergence from bankruptcy. Although the effective date of the Restructuring Plan was January 6, 2017, the Company accounted for the consummation of the Restructuring Plan as if it had occurred on the Fresh Start Reporting Date, January 1, 2017 and implemented Fresh Start reporting as of that date. The adoption of Fresh Start accounting resulted in a new reporting entity, the Successor, for financial reporting purposes. The presentation is analogous to that of a new business entity such that on the Plan Effective Date the Successor's consolidated financial statements reflect a new capital structure with no beginning retained earnings or deficit and a new basis in the identifiable assets and liabilities assumed which includes the elimination of Predecessor accumulated depreciation and accumulated amortization. Upon the Company's emergence from the Chapter 11 Proceeding, the Company qualified for and adopted Fresh Start accounting in accordance with the provisions set forth in ASC 852 based on the following two conditions: (i) holders of existing voting shares of the Predecessor immediately before the Plan Effective Date received less than 50.0% of the voting shares of the Successor and (ii) the reorganization value of the Successor was less than its post-petition liabilities and estimated allowed claims.

As part of Fresh Start accounting, the Company was required to determine the reorganization value of the Successor upon emergence from the Chapter 11 Proceeding. Reorganization value approximates the fair value of the entity, before considering liabilities, and approximates the amount a willing buyer would pay for the assets of the entity immediately after the restructuring. The fair value of the Successor's assets was determined with the assistance of a third-party valuation expert who used available comparable market data and quotations, discounted cash flow analysis, and other methods in determining the appropriate asset fair values. The reorganization value was allocated to the Company's individual assets based on their estimated fair values.

Enterprise value, which was used to derive reorganization value, represents the estimated fair value of an entity’s capital structure which generally consists of long term debt and stockholders’ equity. The Successor’s enterprise value was approved by the Bankruptcy Court in support of the Restructuring Plan and was not to exceed $750.0 million, which

-18-

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

represented the mid-point of a determined range of $600.0 million to $900.0 million. The Successor's enterprise value of $750.0 million was based upon $725.9 million of New Equity and New Warrants as approved by the Bankruptcy Court and $24.1 million of other liabilities that were not eliminated or discharged under the Restructuring Plan. The Successor's enterprise value was determined with the assistance of a separate third-party valuation expert who used available comparable market data and quotations, discounted cash flow analysis and other internal financial information and projections. This enterprise value combined with the Company’s Rights Offering was the basis for deriving equity value. The Company’s estimates of fair value are inherently subject to significant uncertainties and contingencies beyond its control. Accordingly, there can be no assurance that the estimates, assumptions, valuations, appraisals and financial projections will be realized, and actual results could vary materially. Moreover, the market value of the Company’s common stock subsequent to its emergence from bankruptcy may differ materially from the equity valuation derived for accounting purposes.

Machinery and Equipment

The fair value of machinery and equipment was estimated with the assistance of the third-party valuation expert, and the market approach, the cost approach, and the income approach were considered for each individual asset. The market approach and the cost approach were the primary approaches that were relied upon to value these assets. Although the income approach was not applied to value the machinery and equipment assets individually, the Company did consider the earnings of the reporting unit within which each of these assets reside. Because more than one approach was used to develop a valuation, the various approaches were reconciled to determine a final value conclusion.

Under the cost approach, the valuation estimate was based upon a determination of replacement cost new (RCN), reproduction cost new (CRN), or a combination of both. Once the RCN and CRN estimates were adjusted for physical and functional conditions, they were then compared to market data and other indications of value, where available, to confirm results obtained by the cost approach. Where direct RCN estimates were not available or deemed inappropriate, the CRN for machinery and equipment was estimated using the indirect, or trending, method in which percentage changes in applicable price indices were applied to historical costs to convert them into indications of current costs. To estimate the CRN amounts, inflation indices from established external sources were then applied to historical costs to estimate the CRN for each such asset.

The Company also developed a cost approach when market information was not available or a market approach was deemed inappropriate. In doing so, an indicated value was derived by deducting physical deterioration from the RCN or CRN of each identifiable asset. Physical deterioration is the loss in value or usefulness of a property due to the using up or expiration of its useful life caused by wear and tear, deterioration, exposure to various elements, physical stresses, and similar factors.

Under the market approach, the valuation estimate was based upon an analysis of recent sales transactions for comparable assets and took into account physical, functional and economic conditions. Where comparable sales transactions could not be reasonably obtained, the Company utilized the percent of cost technique under the market approach, which takes into consideration general sales, sales listings, and auction data for each major asset category. This information was then used in conjunction with each asset’s effective age to develop ratios between the sales price and RCN or CRN of similar asset types. A market-based depreciation curve was then developed and applied to asset categories where sufficient sales and auction information existed.

Economic obsolescence related to machinery and equipment was also considered and was applied to stacked and underutilized assets based upon the status of the asset. Economic obsolescence was also considered in situations in which the earnings of the applicable business segment in which the assets are employed suggest economic obsolescence. When penalizing assets for economic obsolescence, an additional economic obsolescence penalty was levied, while considering scrap value to be the floor value for an asset.

Land, Buildings and Leasehold Improvements

The fair value estimates of the real property assets were estimated with the assistance of the third-party valuation expert, and the market approach, the cost approach, and the income approach were considered for each of the Company's significant real property assets. The Company primarily relied upon the market and cost approaches.

In valuing the fee simple interest in the land, the Company utilized the sales comparison approach under the market approach. The sales comparison approach estimates value based upon the price in which other purchasers and sellers have agreed to transact for comparable properties. This approach is based on the principle of substitution, which states that the limits of prices, rents and rates tend to be set by the prevailing prices, rents and rates of equally desirable substitutes. In conducting the sales comparison approach, data was gathered on comparable properties and adjustments were made for factors including

-19-

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

market conditions, size, access/frontage, zoning, location, and conditions of sale. Greatest weight was typically given to the comparable sales in proximity and similar in size to each of the owned sites.

In valuing the fee simple interest in buildings and leasehold improvements, the Company utilized the direct and indirect methods of the cost approach. For the direct method cost approach analysis, the Company first had to determine the RCN. In order to estimate the RCN of the buildings and leasehold improvements, various factors were considered including building size, year built, number of stories, and the breakout of the space, property history, maintenance history, and insurable value costs. For the indirect method cost approach, the Company first had to estimate a CRN for leasehold improvements being valued via the indirect, or trending, method of the cost approach. To estimate the CRN amounts, the Company applied published inflation indices obtained from third-party sources to each asset’s historical cost to convert the known cost into an indication of current cost.

Once the RCN and CRN of the buildings and leasehold improvements was computed, the Company estimated an allowance for physical depreciation for the buildings and leasehold improvements based upon their respective age.

Intangible Assets

The financial information used to estimate the fair values of intangible assets was consistent with the information used in estimating the Company’s enterprise value. Tradenames were valued primarily utilizing the relief from royalty method of the income approach. Significant inputs and assumptions included remaining useful lives, the forecasted revenue streams, applicable royalty rates, tax rates, and applicable discount rates. Customer relationships were considered in the analysis, but based on the valuation under the excess earnings methodology, no value was attributed to customer relationships.

The following table reconciles the enterprise value to the estimated fair value of the Successor common stock as of the Fresh Start Reporting Date (in thousands):



Enterprise value	$	750,000
Add: Cash and cash equivalents	181,242
Less: Emergence costs settled in cash post-emergence	(5,378		)
Fair value of New Equity and New Warrants, including Rights Offering	925,864
Less: Rights Offering proceeds	(200,000		)
Less: Fair value of New Warrants	(20,385		)
Fair value of Successor common stock, prior to Rights Offering	$	705,479

Shares outstanding on January 1, 2017, prior to Rights Offering shares	39,999,997
Per share value	$	17.64

The following table reconciles the enterprise value to the reorganization value of the Successor assets on the Effective Date (in thousands):



Enterprise value	$	750,000
Add: Cash and cash equivalents	181,242
Less: Emergence costs settled in cash post-emergence	(5,378		)
Add: Other current liabilities	165,501
Add: Other long-term liabilities and deferred tax liabilities	22,666
Reorganization value of Successor assets	$	1,114,031

The following table summarizes the impact of the reorganization and the Fresh Start accounting adjustments on the Company's consolidated balance sheet on the Fresh Start Reporting Date. The reorganization value has been allocated to the assets acquired based upon their estimated fair values, as shown below. The estimated fair values of certain assets and liabilities, including property, plant and equipment, other intangible assets, taxes (including uncertain tax positions), and contingencies required significant judgments and estimates (in thousands):

-20-

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)



	Predecessor			Reorganization Adjustments				Fresh Start Adjustments				Successor

ASSETS
Current assets:
Cash and cash equivalents	$	64,583		$	116,659		(a)	$	—			$	181,242
Accounts receivable	137,222			—				—				137,222
Inventories, net	54,471			—				—				54,471
Prepaid and other current assets	37,392			—				—				37,392
Deferred tax assets	6,020			—				—				6,020
Total current assets	299,688			116,659				—				416,347
Property, plant and equipment, net	950,811			—				(347,921		)	(h)	602,890
Other assets:
Intangible assets, net	76,057			—				(15,657		)	(h)	60,400
Deferred financing costs	—			2,248			(b)	—				2,248
Other noncurrent assets	35,045			—				(2,899		)	(h)	32,146
Total assets	$	1,361,601		$	118,907			$	(366,477	)		$	1,114,031
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities:
Accounts payable	$	75,193		$	16,848		(c)	$	—			$	92,041
Payroll and related costs	18,287			—				—				18,287
Accrued expenses	59,129			(5,985		)	(c)	—				53,144
DIP Facility	25,000			(25,000		)	(d)	—				—
Other current liabilities	3,026			—				(997		)	(i)	2,029
Total current liabilities	180,635			(14,137		)		(997		)		165,501
Deferred tax liabilities	15,613			—				(4,613		)	(j)	11,000
Other long-term liabilities	18,577			—				(6,911		)	(i)	11,666
Total liabilities not subject to compromise	214,825			(14,137		)		(12,521		)		188,167
Liabilities subject to compromise	1,445,346			(1,445,346		)	(e)	—				—
Commitments and contingencies
Shareholders' equity:
Common stock	1,195			(640		)	(f)	—				555
Additional paid-in capital	1,009,426			926,504			(f)	(1,010,621		)	(k)	925,309
Accumulated other comprehensive loss	(2,600		)	—				2,600			(k)	—
Retained earnings (deficit)	(1,306,591		)	652,526			(g)	654,065			(l)	—
Total shareholders' equity (deficit)	(298,570		)	1,578,390				(353,956		)	(l)	925,864
Total liabilities and shareholders' equity	$	1,361,601		$	118,907			$	(366,477	)		$	1,114,031

Reorganization adjustments

(a) Represents the reorganization adjustment to cash and cash equivalents (in thousands):

-21-

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)




Cash settlement of general unsecured and other reinstated claims	$	(33,898	)
Payment of professional fees and success fees paid	(21,657		)
Repayment of DIP Facility borrowing and accrued interest	(25,538		)
Proceeds from the Rights Offering	200,000
Payment of deferred financing costs related to the New Credit Facility	(2,248		)
Net impact to cash and cash equivalents	$	116,659

(b) Represents deferred loan costs associated with the closing of the New Credit Facility.



Accounts payable:
Pre-petition liabilities related to contract cures, 503(b)(9) claims and critical vendors	$	16,848

Accrued expenses:
Settlement of professional fees	$	(10,135	)
Reinstate liability for acquisition holdback	4,100
Settlement of accrued interest related to the DIP Facility	(538		)
Other accrued expenses	588
Net impact to accrued expenses	$	(5,985	)

(d) Represents the repayment of the DIP Facility.

(e) Represents the settlement of liabilities subject to compromise in accordance with the Restructuring Plan (in thousands):




Fair value of Successor common stock	$	(705,479	)
Fair value of New Warrants issued per the Restructuring Plan	(20,385		)
Fair value of reinstated accounts payable and accrued liabilities to be settled in cash	(20,083		)
General unsecured creditor claims settled in cash	(33,000		)
Gain on settlement of liabilities subject to compromise	(666,399		)
Net impact to liabilities subject to compromise	$	(1,445,346	)

(f) Represents the reorganization adjustments to common stock and additional paid in capital (in thousands):




Common stock:
Cancellation of Predecessor common shares	$	(1,195	)
Issuance of Successor common stock	555
Net impact to common stock	$	(640	)

Additional paid in capital:
Fair value of Successor common stock	$	705,479
Fair value of New Warrants issued per the Restructuring Plan	20,385
Proceeds from the Rights Offering	200,000
Cancellation of Predecessor common shares	1,195
Issuance of Successor common stock	(555		)
Net impact to additional paid in capital	$	926,504

-22-

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

(g) Represents the reorganization adjustments to retained deficit (in thousands):




Gain on settlement of liabilities subject to compromise	$	666,399
Accrual of success fee	(13,435		)
Adjustment for other expenses	(438		)
Net impact to retained deficit	$	652,526

Fresh Start adjustments

(h) Represents the Fresh Start accounting adjustments based upon the individual asset fair values.

(i) Represents the accelerated recognition of deferred gain balances of the Predecessor.

(j) Represents the tax effect of the above Fresh Start accounting adjustments.

(k) Represents the adjustment to Predecessor additional paid-in capital as a result of the elimination of Predecessor retained deficit and accumulated other comprehensive loss in accordance with ASC 852.

(l) Represents the income statement impacts of the revaluation loss of $354.0 million, after tax, and the elimination of the resulting retained deficit balance in accordance with ASC 852.

Note 4 - Debt

Debt consisted of the following as of June 30, 2017 and December 31, 2016 (in thousands):



	Successor		Predecessor
	June 30, 2017		December 31, 2016
Revolving Credit Facility	$	—	$	284,400
Five-Year Term Loans	—		569,250
Seven-Year Term Loans	—		480,150
Total debt	—		1,333,800
Less: liabilities subject to compromise	—		(1,333,800		)
Long-term debt	$	—	$	—

DIP Facility	$	—	$	25,000

Amended Credit Facility	$	—	$	—

On July 20, 2016, the Debtors filed Bankruptcy Petitions in the Bankruptcy Court seeking relief under Chapter 11 of the Bankruptcy Code under the caption “In re: CJ Holding Co., et al., Case No. 16-33590.” The filing of the Bankruptcy Petitions constituted an event of default with respect to the Original Credit Agreement. As a result, the Company’s pre-petition secured indebtedness under the Original Credit Agreement became immediately due and payable and any efforts to enforce such payment obligations were automatically stayed as a result of the Chapter 11 Proceeding. As of December 31, 2016, $1.3 billion of debt under the Original Credit Agreement was classified as liabilities subject to compromise.

Additional information regarding the Chapter 11 Proceeding is included in Note 2 - Chapter 11 Proceeding and Emergence.

Amended Credit Facility

-23-

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

On January 6, 2017, in connection with the emergence from bankruptcy, the Company entered into the New Credit Facility, and subsequently on May 4, 2017, entered into the Amended Credit Facility.

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

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

The Borrowers’ obligations under the Amended 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 Amended Credit Facility.

At the Borrowers’ election, interest on borrowings under the Amended Credit Facility will be 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 will be subject to a monthly step-up of 0.25% in the event that average excess availability under the Amended Credit Facility is 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 Amended Credit Facility is equal to or greater than 62.5% of the total commitment. 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. The Borrowers will also be required to pay a fee on the unused portion of the Amended Credit Facility equal to (i) 0.75% in the event that utilization is less than 25.0% of the total commitment, (ii) 0.50% in the event utilization is 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 is equal to or greater than 50% of the total commitment.

The Amended Credit Facility contains covenants that limit the Borrowers’ and their subsidiaries’ 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 Amended Credit Facility also contains a financial covenant that requires 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 is generally defined in the Amended 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, 2017, the Company was in compliance with all financial covenants.

DIP Facility

On July 29, 2016, the Predecessor entered into a $100.0 million Superpriority Secured Debtor-in-Possession Credit Agreement (the “DIP Credit Agreement”) with the other Debtors, the DIP Lenders and Cortland Capital Market Services LLC, as administrative agent.

The borrowers under the DIP Facility were the Predecessor and CJ Holding Co. All obligations under the DIP Facility were guaranteed by the Company’s subsidiaries that were debtors in the Bankruptcy cases. Borrowings under the DIP Credit Agreement were generally secured by superpriority priming liens on substantially all of the assets of the borrowers and guarantors.

Amounts outstanding under the DIP Facility bore interest based on, at the option of the borrower, LIBOR or an alternative base rate, plus an applicable margin equal to 9.0% in the case of LIBOR loans and 8.0% in the case of base rate

-24-

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

loans. The alternative base rate was equal to the highest of (i) the published ‘prime rate’, (ii) the Federal Funds Effective Rate (as defined in the DIP Credit Agreement) plus 0.5% and (iii) LIBOR plus 1.0%. The DIP Facility also required that the Company pay various fees to the DIP Lenders, including a commitment fee equal to 5.0% of the unused commitments thereunder. The DIP Facility was scheduled to mature on March 31, 2017.

In accordance with the Restructuring Plan, on the Plan Effective Date, the Company repaid all amounts outstanding under the DIP Facility with the proceeds from the Rights Offering and the DIP Facility was canceled and discharged.

Predecessor Credit Agreements

On March 24, 2015, in connection with the closing of the Nabors Merger, the Predecessor entered into the Original Credit Agreement. The Original Credit Agreement provided for senior secured credit facilities in an aggregate principal amount of $1.66 billion, consisting of (i) a revolving credit facility (“Revolving Credit Facility” or the “Revolver”) in the aggregate principal amount of $600.0 million and (ii) a term loan B facility (“Term Loan B”) in the aggregate principal amount of $1.06 billion. The Company simultaneously repaid all amounts outstanding and terminated Old C&J’s prior credit agreement; no penalties were due in connection with such repayment and termination. All obligations under the Original Credit Agreement were guaranteed by the Predecessor’s wholly-owned domestic subsidiaries, other than immaterial subsidiaries.

On September 29, 2015, the Company obtained and the Predecessor entered into a waiver and amendments to the Original Credit Agreement, which, among other things, suspended certain financial covenants set forth in the Original Credit Agreement. The suspension of these financial covenants commenced with the fiscal quarter ending September 30, 2015 and would have lasted through the fiscal quarter ending June 30, 2017.

On May 10, 2016, the Company obtained a temporary limited waiver agreement from certain of the lenders pursuant to which, effective as of March 31, 2016, such lenders agreed to not consider a breach of the Minimum Cumulative Consolidated EBITDA (as defined in the Original Credit Agreement) covenant measured as of March 31, 2016 an event of default through May 31, 2016.

On May 31, 2016, the Company obtained and the Predecessor entered into the Forbearance Agreement with certain of the lenders pursuant to which, among other things, such lenders agreed not to pursue default remedies against the Company with respect to its breach of the Minimum Cumulative Consolidated EBITDA Covenant or certain specified payment defaults.

On June 30, 2016, this forbearance was extended through July 17, 2016 pursuant to the Second Forbearance Agreement, and prior to the termination of the Second Forbearance Agreement, this forbearance period was once again extended through July 20, 2016. The Second Forbearance Agreement provided that the forbearance would terminate upon the occurrence of certain events, including the failure of the Predecessor to enter into the Restructuring Support Agreement on or prior to July 8, 2016. On July 8, 2016, the Predecessor entered into the Restructuring Support Agreement with the Supporting Lenders. The Restructuring Support Agreement contemplated the implementation of a restructuring of the Company through a debt-to-equity conversion and Rights Offering, which transaction was effectuated through the Restructuring Plan.

On July 20, 2016, the Debtors filed Bankruptcy Petitions in the Bankruptcy Court seeking relief under Chapter 11. Additional information, including definitions of capitalized defined terms, regarding the Chapter 11 Proceeding is included in Note 2 - Chapter 11 Proceeding and Emergence.

Revolving Credit Facility

The Revolver was scheduled to mature on March 24, 2020 (except that if any Five-Year Term Loans (as defined herein) had not been repaid prior to September 24, 2019, the Revolver was scheduled to mature on September 24, 2019). Borrowings under the Revolver were non-amortizing. Amounts outstanding under the Revolver bore interest based on, at the option of the borrower, LIBOR or an alternative base rate, plus an applicable margin determined pursuant to a pricing grid based on the ratio of consolidated total indebtedness of C&J and its subsidiaries to Consolidated EBITDA of C&J and its subsidiaries for the most recent four fiscal quarter period for which financial statements are available (the “Total Leverage Ratio”).

On July 20, 2016, the Debtors filed the Bankruptcy Petitions which constituted an event of default under the Original Credit Agreement and accelerated the Revolver and Term Loan B Facility indebtedness to become immediately due and payable. On the Plan Effective Date, pursuant to the Restructuring Support Agreement entered into on July 8, 2016,

-25-

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

holders of the Revolver and Term Loan B Facility received their pro rata share of 100.0% of the New Equity in the Successor, subject to dilution from the issuance of New Equity on account of the Management Incentive Plan, the Rights Offering, the Backstop Fee and the New Warrants as discussed further in Note 2 - Chapter 11 Proceeding and Emergence.

Term Loan B Facility

Borrowings under the Term Loan B were comprised of two tranches: a tranche consisting of $575.0 million in aggregate principal amount of term loans maturing on March 24, 2020 (the “Five-Year Term Loans”) and a tranche consisting of a $485.0 million in aggregate principal amount of term loans maturing on March 24, 2022 (the “Seven-Year Term Loans”). The Company was required to make quarterly amortization payments in an amount equal to 1.0%, with the remaining balance payable on the applicable maturity date. As of December 31, 2016, the Company had borrowings outstanding under the Five-Year Term Loans and the Seven-Year Term Loans of $569.3 million and $480.2 million, respectively.

Five-Year Term Loans outstanding under the Term Loan B bore interest based on, at the option of the Company, (i) LIBOR subject to a floor of 1.0%, plus a margin of 5.5%, or (ii) an alternative base rate, plus a margin of 4.5%. Seven-Year Term Loans outstanding under the Term Loan B bore interest based on, at the option of the Company, (i) LIBOR subject to a floor of 1.0%, plus a margin of 6.25%, or (ii) an alternative base rate, plus a margin of 5.25%.

The alternative base rate was equal to the highest of (i) the administrative agent’s prime rate, (ii) the Federal Funds Effective Rate plus 0.5%, or (iii) LIBOR plus 1.0%.

On July 20, 2016, the Debtors filed the Bankruptcy Petitions which constituted an event of default under the Original Credit Agreement and accelerated the Term Loan B Facility indebtedness to become immediately due and payable; however, any efforts to enforce such payment obligations were automatically stayed as a result of the Chapter 11 Proceeding. On the Plan Effective Date, pursuant to the Restructuring Support Agreement entered into on July 8, 2016, holders of the Term Loan B Facility debt received their pro rata share of 100.0% of the New Equity in the Successor, subject to dilution from the issuance of New Equity on account of the Management Incentive Plan, the Rights Offering, the Backstop Fee and the New Warrants as discussed further in Note 2 - Chapter 11 Proceeding and Emergence.

Interest Expense

As of June 30, 2016, based on the negotiations between the Company and the lenders, it became evident that the restructuring of the Company's capital structure would not include a restructuring of the Company's Revolving Credit Facility, the Five-Year Term Loans and the Seven-Year Term Loans, and these debt obligations, as demand obligations, would not be paid in the ordinary course of business over the term of these loans. As a result, during the second quarter of 2016, the Company accelerated the amortization of the associated original issue discount and deferred financing costs, fully amortizing these amounts as of June 30, 2016. For the three and six months ended June 30, 2017 (Successor) and 2016 (Predecessor), interest expense consisted of the following (in thousands):



	Successor			Predecessor
	Three Months Ended June 30, 2017			Three Months Ended June 30, 2016

Amended Credit Facility	$	426		$	—
Original Credit Agreement	—			25,322
Capital leases	157			337
Accretion of original issue discount	—			2,113
Amortization of deferred financing costs	153			2,310
Original issue discount accelerated amortization	—			48,221
Deferred financing costs accelerated amortization	—			43,720
Interest income and other	(322		)	(89		)
Interest expense, net	$	414		$	121,934

-26-

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)



	Successor			Predecessor
	Six Months Ended June 30, 2017			Six Months Ended June 30, 2016

Amended Credit Facility	$	876		$	—
Credit Agreements	—			46,215
Capital leases	314			570
Accretion of original issue discount	—			4,192
Amortization of deferred financing costs	306			4,589
Original issue discount accelerated amortization	—			48,221
Deferred financing costs accelerated amortization	—			43,720
Interest income and other	(391		)	(106		)
Interest expense, net	$	1,105		$	147,401

Note 5 - Goodwill and Other Intangible Assets

During the first quarter of 2016, utilization and commodity price levels continued to fall towards unprecedented levels and the resulting negative impact on the Company’s results of operations, coupled with the sustained decrease in the Company’s stock price, were deemed triggering events that led to an interim period test for goodwill impairment. The Company chose to bypass a qualitative approach and instead opted to employ the detailed Step 1 impairment testing methodologies discussed below.

Income approach

The income approach impairment testing methodology is based on a discounted cash flow model, which utilizes present values of cash flows to estimate fair value. For the Completion Services and Well Support Services reporting units, the future cash flows were projected based on estimates of projected revenue growth, fleet and rig count, utilization, gross profit rates, SG&A rates, working capital fluctuations, and capital expenditures. For the Other Services reporting unit, the future cash flows were projected based primarily on estimates of future demand for manufactured and refurbished equipment as well as parts and service, gross profit rates, SG&A rates, working capital fluctuations, and capital expenditures. Forecasted cash flows for the three reporting units took into account known market conditions as of March 31, 2016, and management’s anticipated business outlook, both of which have been impacted by the sustained decline in commodity prices.

A terminal period was used to reflect an estimate of stable, perpetual growth. The terminal period reflects a terminal growth rate of 2.5% for all three reporting units, including an estimated inflation factor.

The future cash flows were discounted using a market-participant risk-adjusted weighted average cost of capital (“WACC”) of 14.5% for Completion Services, 14.0% for Well Support Services, and 16.0% for Other Services reporting units. These assumptions were derived from unobservable inputs and reflect management’s judgments and assumptions.

Market approach

The market approach impairment testing methodology is based upon the guideline public company method. The application of the guideline public company method was based upon selected public companies operating within the same industry as the Company. Based on this set of comparable competitor data, price-to-earnings multiples were derived and a range of price-to-earnings multiples was determined for each reporting unit. Selected market multiples were 10.6x for Completion Services, 10.5x for Well Support Services and 11.0x for Other Services reporting units.

The fair value determined under the market approach is sensitive to these market multiples, and a decline in any of the multiples could reduce the estimated fair value of any of the three reporting units below their respective carrying values. Earnings estimates were derived from unobservable inputs that require significant estimates, judgments and assumptions as described in the income approach.

The estimated fair value determined under the income approach was consistent with the estimated fair value

-27-

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

determined under the market approach. The concluded fair value for the Completion Services and Well Support Services reporting units consisted of a weighted average, with an 80.0% weight under the income approach and a 20.0% weight under the market approach. The concluded fair value for the Other Services reporting unit consisted of a weighted average with a 50.0% weight under the income approach and a 50.0% weight under the market approach.

The results of the Step 1 impairment testing indicated potential impairment in the Well Support Services reporting unit. The goodwill associated with both the Completion Services and Other Services reporting units was completely impaired during the third quarter of 2015. As a way to validate the estimated reporting unit fair values, the total market capitalization of the Company was compared to the total estimated fair value of all reporting units, and an implied control premium was derived. Market data in support of the implied control premium was used in this reconciliation to corroborate the estimated reporting unit fair values.

Step 2 of the goodwill impairment testing for the Well Support Services reporting units was performed during the first quarter of 2016, and the results concluded that there was no value remaining to be allocated to the goodwill associated with this reporting unit. As a result, the Company recognized impairment expense of $314.8 million during the first quarter of 2016.

As of June 30, 2017 and December 31, 2016, there was no goodwill remaining to be allocated across the Company's reporting units.

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. During 2016, management determined the sustained low commodity price levels coupled with the sustained decrease in the Company’s share price were deemed triggering events that provided indicators that its definite-lived intangible assets may be impaired. The Company performed a recoverability test on all of its definite-lived intangible assets and PP&E by comparing the estimated future net undiscounted cash flows expected to be generated from the use of these assets to the carrying amounts 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.

Recoverability testing through the six months ended June 30, 2016 resulted in the determination that certain intangible assets associated with the Company’s wireline and artificial lift lines of business were not recoverable. The fair value of the wireline and artificial lift intangible assets was determined to be approximately $38.2 million and zero, respectively, resulting in impairment expense of $50.4 million and $4.6 million, respectively.

The changes in the carrying amounts of other intangible assets for the six months ended June 30, 2017 are as follows (in thousands):



		Predecessor						Successor
	Amortization Period	December 31, 2016			Fresh Start Adjustments			On January 1, 2017		Amortization Expense			Divestiture			June 30, 2017
Customer relationships	8-15 years	$	80,826		$	(80,826	)	$	—	$	—		$	—		$	—
Trade name	10-15 years	29,994			26,506			56,500		—			—			56,500
Developed technology	5-15 years	21,516			(17,616		)	3,900		—			(3,900		)	—
Non-compete	4-5 years	2,600			(2,600		)	—		—			—			—
Patents	10 years	35			(35		)	—		—			—			—
		134,971			(74,571		)	60,400		—			(3,900		)	56,500
Less: accumulated amortization		(58,914		)	58,914			—		(1,883		)	—			(1,883		)
Intangible assets, net		$	76,057		$	(15,657	)	$	60,400	$	(1,883	)	$	(3,900	)	$	54,617

Note 6 - Share-Based Compensation

-28-

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Successor Equity Plan

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, 2017, only nonqualified stock options and restricted shares 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 six months ended June 30, 2017, approximately 0.3 million nonqualified stock options were granted under the MIP to certain of the Company's executive officers at a fair market value of $34.52 per nonqualified stock option. These option awards will expire on the tenth anniversary of the grant date and will vest over three years of continuous service with 34% vesting immediately upon the grant date, and 22% on each of the first, second and third anniversaries of the grant date.

As of June 30, 2017, the Company had approximately 0.3 million options outstanding to employees. The Company had approximately $5.1 million of share-based compensation remaining to be expensed over a weighted average remaining service period of 2.6 years.

The following table includes the assumptions used in determining the fair value of option awards granted during the first three months of 2017.



Expected volatility		96.4%
Expected dividends		None
Exercise price		$42.65
Expected term (in years)		5.7
Risk-free rate		2.03%

Restricted Stock

Restricted stock is valued based on the closing price of the Company’s common stock on the NYSE on the date of grant. During the six months ended June 30, 2017, approximately 0.9 million shares of restricted stock were granted to employees and non-employee directors under the MIP, at fair market values ranging from $34.05 to $44.90 per share of restricted stock. Restricted stock awards granted to employees will vest over three years of continuous service with 34% vesting 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.

-29-

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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, 2017, the Company had not issued any dividends.

As of June 30, 2017, the Company had approximately 0.6 million shares of restricted stock outstanding to employees and non-employee directors. The Company had $20.5 million of share-based compensation remaining to be expensed over a weighted average remaining service period of 2.6 years.

Predecessor Equity Plans

In connection with the Nabors Merger, the Company approved and adopted the C&J Energy Services 2015 Long Term Incentive Plan (the “2015 LTIP”), effective as of March 23, 2015. The 2015 LTIP served as an assumption of the Old C&J 2012 Long-Term Incentive Plan, including the sub-plan titled the C&J International Middle East FZCO Phantom Equity Arrangement (the “2012 LTIP”), with certain non-material revisions made and no increase in the number of shares remaining available for issuance under the 2012 LTIP. Prior to the adoption of the 2015 LTIP, all share-based awards granted to Old C&J employees, consultants and non-employee directors were granted under the 2012 LTIP and, following the 2015 LTIP’s adoption, no further awards were granted under the 2012 LTIP. Awards that were previously outstanding under the 2012 LTIP continued to remain outstanding under the 2015 LTIP, as adjusted to reflect the Nabors Merger. At the closing of the Nabors Merger, restricted shares and stock option awards were granted under the 2015 LTIP to certain employees of the C&P Business and approximately 0.4 million C&J common shares underlying those awards were deemed part of the consideration paid to Nabors for the Nabors Merger.

The 2015 LTIP provided for the grant of share-based awards to the Company’s employees, consultants and non-employee directors. The following types of awards were available for issuance under the 2015 LTIP: incentive stock options and nonqualified stock options, share appreciation rights, restricted shares, restricted share units, dividend equivalent rights, performance awards and share awards.

Approximately 11.3 million shares were available for issuance under the 2015 LTIP as of December 31, 2016. The number of common shares available for issuance under the 2015 LTIP was 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 2015 LTIP was terminated as described in Note 2 - Chapter 11 Proceeding and Emergence, pursuant to the Restructuring Plan, the liquidation of C&J Energy Services Ltd. was completed under the laws of Bermuda, and all of the existing shares of the Predecessor's common equity were canceled as of the Effective Date. Also, on the Effective Date, the Successor issued the New Warrants to the holders of the canceled Predecessor common shares, provided that such class of holders voted to accept the Restructuring Plan.

Note 7 - 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,

-30-

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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 presently not possible to determine the ultimate outcome of any pending or potential claims or litigation against the Company; however, management believes that the outcome of those matters that are presently known to the Company will not have a material adverse effect on the Company’s consolidated financial position, results of operations or liquidity.

Contingent Consideration Liability

On May 18, 2015, the Company acquired all of the outstanding equity interests of ESP Completion Technologies LLC, a manufacturer of wellheads, artificial lift completion tools and electric submersible pumps for approximately $34.0 million and including a contingent consideration liability valued at approximately $14.4 million at the date of the acquisition. If the acquiree is able to achieve certain levels of EBITDA over a three-year period, the Company will be obligated to make future tiered payments of up to $29.5 million. The contingent consideration liability is remeasured on a fair value basis each quarter until it is paid or expires. As of June 30, 2017, the earn-out was estimated to have zero value.

Self-Insured Risk Accruals

The Company maintains insurance policies for workers’ compensation, automobile liability, general liability, which also includes sudden and accidental pollution insurance, 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: workers’ compensation of $1,000,000; automobile liability claims of $1,000,000; general liability claims, including sudden and accidental pollution claims, of $250,000, plus an additional annual aggregate deductible of $250,000; and property damage for catastrophic events of $50,000. The excess loss liability coverage is subject to a self-insured retention of $5,000,000 for each occurrence and in the aggregate.

Additionally, under the terms of the Separation Agreement, dated as of February 12, 2015, by and between the Company and Nabors, relating to the Nabors Merger, the Company assumed, among other liabilities, all liabilities of 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; other than certain liabilities for which Nabors has agreed to indemnify the Company. 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 8 - 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 the year ended December 31, 2016, the Company’s reportable segments were: (i) Completion Services, (ii) Well Support Services, and (iii) Other Services. In line with the discontinuance of the small, ancillary service lines and divisions in the Other Services reportable segment, subsequent to the year ended December 31, 2016, the Company is disclosing two reportable segments, and financial information for the Other Services reportable segment is only presented for the corresponding prior year period. The Company's reportable segments are now: (i) Completion Services and (ii) 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. The following is a brief description of the Company's reportable segments:

Completion Services

-31-

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

The Company’s Completion Services segment consists of the following businesses and service lines: (1) fracturing; (2) cased-hole solutions' wireline and pumping services; (3) well construction & intervention services, which includes cementing, directional drilling and coiled tubing services; and (4) completion support services, which includes our research & technology (R&T) department and data controls instrument business.

Well Support Services

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

Other Services

Other Services consisted of smaller, non-core business lines that have since been divested, including the Company's specialty chemical business, equipment manufacturing and repair business and international coiled tubing operations in the Middle East. In line with the discontinuance of these small, ancillary service lines and divisions, subsequent to the year ended December 31, 2016, the Company is now disclosing two reportable segments, and financial information for the Other Services reportable segment is only presented for the corresponding prior year period.

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

-32-

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)



	Completion Services			Well Support Services			Other Services			Corporate / Elimination			Total
Three months ended June 30, 2017 (Successor)
Revenue from external customers	$	294,147		$	95,996		$	—		$	—		$	390,143
Inter-segment revenues	175			256			—			(431		)	—
Depreciation and amortization	19,479			12,327			—			1,027			32,833
Operating income (loss)	28,886			(7,900		)	—			(34,230		)	(13,244		)
Net income (loss)	26,411			(7,833		)	—			(31,299		)	(12,721		)
Adjusted EBITDA	47,781			1,927			—			(24,598		)	25,110
Capital expenditures	56,660			3,750			—			552			60,962
Six months ended June 30, 2017 (Successor)
Revenue from external customers	$	512,075		$	192,262		—			—			$	704,337
Inter-segment revenues	223			297			—			(520		)	—
Depreciation and amortization	38,090			24,334			—			2,015			64,439
Operating income (loss)	39,091			(16,133		)	—			(72,610		)	(49,652		)
Net loss	36,091			(14,321		)	—			(66,792		)	(45,022		)
Adjusted EBITDA	70,417			5,751			—			(46,474		)	29,694
Capital expenditures	64,094			7,771			—			682			72,547
As of June 30, 2017 (Successor)
Total assets	$	685,944		$	319,555		$	—		$	331,348		$	1,336,847
Three months ended June 30, 2016 (Predecessor)
Revenue from external customers	$	135,579		$	87,732		$	1,857		$	—		$	225,168
Inter-segment revenues	234			—			10,794			(11,028		)	—
Depreciation and amortization	35,754			16,711			683			1,135			54,283
Operating loss	(101,663		)	(12,095		)	(21,973		)	(46,706		)	(182,437		)
Net loss	(101,828		)	(11,416		)	(26,104		)	(151,768		)	(291,116		)
Adjusted EBITDA	(20,184		)	4,004			(597		)	(16,447		)	(33,224		)
Capital expenditures	4,261			3,946			548			9,015			17,770
Six months ended June 30, 2016 (Predecessor)
Revenue from external customers	$	306,406		$	184,684		3,693			—			$	494,783
Inter-segment revenues	384			—			25,844			(26,228		)	—
Depreciation and amortization	74,836			35,257			1,424			1,719			113,236
Operating loss	(220,732		)	(349,934		)	(27,542		)	(84,644		)	(682,852		)
Net loss	(220,979		)	(346,735		)	(31,842		)	(119,973		)	(719,529		)
Adjusted EBITDA	(35,769		)	7,835			(2,509		)	(34,823		)	(65,266		)
Capital expenditures	9,718			4,847			8,444			13,428			36,437
As of June 30, 2016 (Predecessor)
Total assets	$	856,762		$	530,221		$	74,789		$	79,629		$	1,541,401

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 compensate for the limitations in utilizing Adjusted EBITDA as an operating measure, management also uses U.S. GAAP

-33-

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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, 2017 (Successor) and 2016 (Predecessor), and on a reportable segment basis for the three and six months ended June 30, 2017 (Successor) and 2016 (Predecessor).



	Successor			Predecessor
	Three Months Ended June 30, 2017			Three Months Ended June 30, 2016
Net loss	$	(12,721	)	$	(291,116	)
Interest expense, net	414			121,934
Income tax benefit	(2,393		)	(11,252		)
Depreciation and amortization	32,833			54,283
Other (income) expense, net	1,456			(2,003		)
(Gain) loss on disposal of assets	(3,136		)	1,712
Impairment expense	—			48,712
Severance, facility closures and other	804			12,761
Acquisition-related costs	—			3,379
Customer settlement/bad debt write-off	—			(433		)
Inventory write-down	—			11,780
Incremental insurance reserve	—			548
Restructuring costs	7,853			15,451
Legal settlement	—			1,020
Adjusted EBITDA	$	25,110		$	(33,224	)



	Successor			Predecessor
	Six Months Ended June 30, 2017			Six Months Ended June 30, 2016
Net loss	$	(45,022	)	$	(719,529	)
Interest expense, net	1,105			147,401
Income tax benefit	(5,629		)	(105,399		)
Depreciation and amortization	64,439			113,236
Other (income) expense, net	(106		)	(5,325		)
(Gain) loss on disposal of assets	(9,192		)	4,914
Impairment expense	—			430,406
Severance, facility closures and other	804			23,069
Share-based compensation expense acceleration	15,658			7,792
Acquisition-related costs	—			7,068
Customer settlement/bad debt write-off	—			1,035
Inventory write-down	—			13,047
Incremental insurance reserve	—			548
Restructuring costs	7,637			15,451
Legal settlement	—			1,020
Adjusted EBITDA	$	29,694		$	(65,266	)

-34-

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)



	Three Months Ended June 30, 2017 (Successor)
	Completion Services			Well Support Services			Corporate / Elimination			Total
Net income (loss)	$	26,411		$	(7,833	)	$	(31,299	)	$	(12,721	)
Interest expense, net	290			66			58			414
Income tax benefit	—			—			(2,393		)	(2,393		)
Depreciation and amortization	19,479			12,327			1,027			32,833
Other (income) expense, net	2,185			(134		)	(595		)	1,456
Gain on disposal of assets	(503		)	(2,508		)	(125		)	(3,136		)
Severance, facility closures and other	—			—			804			804
Restructuring costs	(81		)	9			7,925			7,853
Adjusted EBITDA	$	47,781		$	1,927		$	(24,598	)	$	25,110



	Six Months Ended June 30, 2017 (Successor)
	Completion Services			Well Support Services			Corporate / Elimination			Total
Net income (loss)	$	36,091		$	(14,321	)	$	(66,792	)	$	(45,022	)
Interest expense, net	446			40			619			1,105
Income tax benefit	—			—			(5,629		)	(5,629		)
Depreciation and amortization	38,090			24,334			2,015			64,439
Other (income) expense, net	2,554			(1,853		)	(807		)	(106		)
(Gain) loss on disposal of assets	(6,718		)	(2,472		)	(2		)	(9,192		)
Severance, facility closures and other	—			—			804			804
Restructuring costs	(46		)	23			7,660			7,637
Share-based compensation acceleration	—			—			15,658			15,658
Adjusted EBITDA	$	70,417		$	5,751		$	(46,474	)	$	29,694



	Three Months Ended June 30, 2016 (Predecessor)
	Completion Services			Well Support Services			Other Services			Corporate / Elimination			Total
Net loss	$	(101,828	)	$	(11,416	)	$	(26,104	)	$	(151,768	)	$	(291,116	)
Interest income (expense)	186			(85		)	—			121,833			121,934
Income tax benefit	—			—			—			(11,252		)	(11,252		)
Depreciation and amortization	35,754			16,711			683			1,135			54,283
Impairment expense	40,260			1,099			7,353			—			48,712
Other (income) expense, net	(21		)	(594		)	4,131			(5,519		)	(2,003		)
(Gain) loss on disposal of assets	(87		)	(1,320		)	3,119			—			1,712
Acquisition-related costs	128			—			189			3,062			3,379
Severance, facility closures and other	(204		)	292			3,630			9,043			12,761
Customer settlement/bad debt write-off	250			(683		)	—			—			(433		)
Inventory write-down	5,378			—			6,402			—			11,780
Restructuring costs	—			—			—			15,451			15,451
Incremental insurance reserve	—			—			—			548			548
Legal Settlement	—			—			—			1,020			1,020
Adjusted EBITDA	$	(20,184	)	$	4,004		$	(597	)	$	(16,447	)	$	(33,224	)

-35-

C&J ENERGY SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)



	Six Months Ended June 30, 2016 (Predecessor)
	Completion Services			Well Support Services			Other Services			Corporate / Elimination			Total
Net loss	$	(220,979	)	$	(346,735	)	$	(31,842	)	$	(119,973	)	$	(719,529	)
Interest expense, net	266			(138		)	—			147,273			147,401
Income tax benefit	—			—			—			(105,399		)	(105,399		)
Depreciation and amortization	74,836			35,257			1,424			1,719			113,236
Impairment expense	100,818			321,687			7,901			—			430,406
Other (income) expense, net	(19		)	(3,061		)	4,300			(6,545		)	(5,325		)
(Gain) loss on disposal of assets	(73		)	(3,115		)	3,119			4,983			4,914
Acquisition-related costs	300			—			209			6,559			7,068
Severance, facility closures and other	2,413			3,280			5,627			11,749			23,069
Customer settlement/bad debt write-off	375			660			—			—			1,035
Inventory write-down	6,294			—			6,753			—			13,047
Incremental insurance reserve	—			—			—			548			548
Restructuring costs	—			—			—			15,451			15,451
Legal settlement	—			—			—			1,020			1,020
Share-based compensation expense acceleration	—			—			—			7,792			7,792
Adjusted EBITDA	$	(35,769	)	$	7,835		$	(2,509	)	$	(34,823	)	$	(65,266	)

Note 9 - Supplemental Cash Flow Disclosures

Listed below are supplemental cash flow disclosures for the six months ended June 30, 2017, the Fresh Start Reporting Date and the six months ended June 30, 2016:



	Successor			Predecessor
	Six Months Ended June 30, 2017			On January 1, 2017			Six Months Ended June 30, 2016
Cash paid for interest	$	914		$	—		$	16,927
Income taxes paid (refunded)	$	(488	)	$	—		$	(14,642	)
Reorganization items, cash	$	—		$	(21,657	)	$	—
Non-cash investing and financing activity:
Change in accrued capital expenditures	$	(3,127	)	$	—		$	(666	)

-36-

Table of Contents

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,” “aim,” “will,” “could,” “should,” “potential,” “would,” “may,” “probable,” “likely,” and similar expressions that convey the uncertainty of future events or outcomes, and the negative thereof, are intended to identify forward-looking statements. Forward-looking statements, which are not generally historical in nature, include those that express a belief, expectation or intention regarding our future activities, plans and goals and our current expectations with respect to, among other things, the impact of our emergence from bankruptcy on our business and relationships, future sales of or the availability for future sale of substantial amounts of our common stock, including the exercise of outstanding Warrants, 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 declining commodity prices, overcapacity and other competitive factors affecting our industry;


•	the cyclical and volatile nature of the oil and gas industry, which impacts the level of drilling, completion and production activity and spending patterns by E&P companies;


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


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


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


•	changes in customer requirements in the markets we serve;


•	costs, delays, regulatory compliance requirements and other difficulties in executing our long-term growth strategy;


•	the effects of 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;


•	adverse weather conditions in oil or gas producing regions;


•	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;


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


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


•	a shortage of qualified workers;


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

-37-

Table of Contents


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


•	accidental damage to or malfunction of equipment;


•	uncertainty regarding our ability to improve our operating structure, financial results and profitability and to maintain relationships with suppliers, customers, employees and other third parties following emergence from bankruptcy and other risks and uncertainties related to our recent emergence from bankruptcy;


•	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 amended credit facility.

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, 2016 (our “2016 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 2016 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.

-38-

Table of Contents

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 2016 Annual Report.

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

Introductory Note and Corporate Overview

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 below), “C&J” or the “Company”) is a leading provider of well construction, well completion, well support and other complementary oilfield services to oil and gas exploration and production (“E&P”) companies in North America. We offer a comprehensive, vertically-integrated suite of services throughout the life cycle of the well, including fracturing, cased-hole wireline and pumping, cementing, coiled tubing, directional drilling, service rigs, fluids management and other completion support and specialty well site services. We are headquartered in Houston, Texas and operate in all active onshore basins in the continental United States and Western Canada.

We were founded in Texas in 1997 as a partnership and converted to a Delaware corporation (“Old C&J”) in connection with our initial public offering which was completed in 2011 with a listing on the New York Stock Exchange (“NYSE”) under the symbol “CJES.” In 2015, Old C&J combined with the completion and production services business (the “C&P Business”) of Nabors Industries Ltd. (“Nabors”) in a transformative transaction (the “Nabors Merger”) that nearly tripled the Company’s size, significantly expanding the Company’s Completion Services business and adding the Well Support Services business to the Company’s service offering. Upon the closing of the Nabors Merger, Old C&J became a subsidiary of C&J Energy Services Ltd., a Bermuda corporation (the “Predecessor” and together with its consolidated subsidiaries for periods prior to the Plan Effective Date, the “Predecessor Companies” or the “Company”), and shares of common stock of Old C&J were converted into common shares of the Predecessor on a 1-for-1 basis.

Due to a severe industry downturn, on July 20, 2016, certain of the Predecessor Companies voluntarily filed petitions for reorganization seeking relief under the provisions of Chapter 11 of the United States Bankruptcy Code in the United States Bankruptcy Court for the Southern District of Texas, Houston Division (the “Bankruptcy Court”), with ancillary recognition proceedings filed in Canada and Bermuda (collectively, the “Chapter 11 Proceeding”).

On December 16, 2016, the Bankruptcy Court entered an order confirming the plan of reorganization (the “Restructuring Plan”) of the Predecessor Companies. On January 6, 2017 (the “Plan Effective Date”), the Predecessor Companies substantially consummated the Restructuring Plan and emerged from the Chapter 11 Proceeding. As part of the transactions undertaken pursuant to the Restructuring Plan, effective on 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. For more information regarding the Chapter 11 Proceeding, see Note 2 - Chapter 11 Proceeding and Emergence in Part I, Item 1 “Financial Statements” of this Quarterly Report.

Upon emergence from the Chapter 11 Proceeding, we adopted Fresh Start accounting in accordance with the provisions set forth in Accounting Standards Codification (“ASC”) 852 - Reorganizations. For more information regarding the adoption of Fresh Start accounting, see Note 3 - Fresh Start Accounting in Part I, Item 1 “Financial Statements” of this Quarterly Report.

The Successor is the successor issuer to the Predecessor for purposes of and pursuant to Rule 12g-3 of the Exchange Act. Accordingly, references to “C&J,” the “Company,” “we,” “us” or “our” in this Quarterly Report are to the Successor, together with our consolidated subsidiaries when referring to periods following the Plan Effective Date, and to the Predecessor Companies when referring to periods prior to the Plan Effective Date.

Contemporaneously with the commencement of the Chapter 11 Proceeding, trading in the Predecessor’s common stock was suspended and ultimately delisted from the NYSE. On April 12, 2017, the Successor completed an underwritten public offering of common stock and its common stock began trading again on the NYSE under the symbol “CJ.”

-39-

Table of Contents

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.

Business Overview

Demand for our services, and therefore our operating and financial performance, is heavily influenced by drilling, completion and production activity by our customers, which is significantly impacted by commodity prices. Beginning in 2011 through mid-2015, we significantly invested in strategic initiatives to strengthen, expand and diversify our business, including through service line diversification, vertical integration and technological advancement. During that time, we rapidly grew the business both organically and through multiple acquisitions, including the Nabors Merger. During 2016 and into the first quarter of 2017, we divested several of our small, non-core businesses, including our specialty chemical business, equipment manufacturing and repair business and the Company’s international coiled tubing operations in the Middle East. These divestitures reflect a refocusing of our growth strategy in line with our goal of being the leading U.S. provider in all of our core businesses.

We believe that our focus on technological advancement (“R&T”) provides a significant strategic benefit through the ability to develop and implement new technologies and quickly respond to changes in customer requirements and industry demand. Our efforts to date have been focused on developing innovative, fit-for-purpose solutions designed to enhance our core service offerings, increase efficiencies, provide cost savings to our operations and add value for our customers. Our R&T initiatives are now generating monthly cost savings for our integrated completion services operations, which is central to our overall strategy of proactively managing our costs to maximize returns. Several of these investments are already delivering value added products and services that, in addition to producing revenue, are creating increasing demand from key customers. In our day-to-day operations, we utilize equipment and products manufactured by our vertically integrated businesses which are managed through our R&T division, and we also sell such equipment and products to third-party customers in the global energy services industry. Additionally, these initiatives help protect market share in the current operating environment and better position us for growth as activity levels continue to improve.

-40-

Table of Contents

Reportable Segments

As of June 30, 2017, our reportable business segments were:

•

Completion Services, which consists of the following businesses and service lines: (1) fracturing; (2) cased-hole solutions' wireline and pumping services; (3) well construction & intervention services, which includes cementing, directional drilling and coiled tubing services; and (4) completion support services, which includes our research & technology (R&T) department and data controls instrument business.


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

We recently reorganized our cementing, directional drilling and coiled tubing service lines and combined them into a service offering called well construction & intervention services, which is included in our Completion Services segment. Prior to the filing of this Quarterly Report, our coiled tubing service line was part of our Well Support Services segment.

Our Other Services segment consisted of smaller, non-core business lines that have since been divested, including our specialty chemical business, equipment manufacturing and repair business and the Company's international coiled tubing operations in the Middle East. In line with the discontinuance of these small, ancillary service lines and divisions, subsequent to the year ended December 31, 2016, the Company is now disclosing two reportable segments, and financial information for the Other Services reportable segment is only presented for the corresponding prior year period.

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 8 - 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 solutions' wireline and pumping services. We utilize our in-house manufacturing capabilities, including our data acquisition and control instruments manufacturing business, to offer a technologically advanced and efficiency focused range of completion techniques. Our strategy is to offer our completion services as a bundled package in order to provide an integrated, value-added solution and maximize efficiency for our customers. Our well construction & intervention services business, which includes cementing, directional drilling and coiled tubing services, and our completion support services business, which includes our R&T department, which includes manufacturing capabilities, are each also managed through our Completion Services segment. The majority of revenue for this segment is generated by our fracturing business.

During the second quarter of 2017, our fracturing business deployed, on average, approximately 490,000 hydraulic horsepower (“HHP”) out of our current fleet of approximately 860,000 HHP. In our cased-hole wireline and pumping business, we deployed, on average, approximately 72 wireline trucks and 62 pumpdown units out of our current fleet of 127 trucks and 66 pumpdown units. In our well construction and intervention services business, we deployed, on average, approximately 21 coiled tubing units out of our average fleet of approximately 44 units, and approximately 29 cementing units out of our current fleet of 34 units. 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.

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. Adjusted EBITDA is a non-GAAP financial measure computed as 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.

For the quarter ended June 30, 2017, revenue from our Completion Services segment was $294.1 million, representing approximately 75.4% of our total revenue, compared with revenue of $217.9 million for the quarter ended March 31, 2017, which represented a 35.0% quarter-over-quarter increase. Adjusted EBITDA from this segment for the quarter ended June 30, 2017 was $47.8 million, compared with $22.6 million of Adjusted EBITDA for the quarter ended March 31, 2017. The following table presents revenue and other operational data for our Completion Services segment for the three months ended June 30, 2017 and 2016 (dollars in thousands):

-41-

Table of Contents



	Successor		Predecessor
	Three Months Ended
	June 30, 2017		June 30, 2016
Revenue
Hydraulic Fracturing	$	183,714	$	81,760
Wireline & Pumpdown	76,644		34,849
Coiled Tubing Services	18,577		11,152
Other (Cementing, Directional Drilling and Research & Technology)	15,212		7,818
Total revenue	$	294,147	$	135,579

Adjusted EBITDA	$	47,781	$	(20,184	)

Average active hydraulic fracturing horsepower	490,000		470,000
Total fracturing stages	3,688		2,721

Average active wireline trucks	72		92

Average active pumpdown units	62		43

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

Please read Note 8 - Segment Information in Part I, Item 1 “Financial Statements” of this Quarterly Report, for 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 reportable segment basis for the three months ended June 30, 2017 and 2016.

During the second quarter, the continued growth in the North American land drilling rig count coupled with shortages of available fracturing equipment resulted in higher overall utilization and pricing levels across our service lines, which significantly improved our second quarter results in our Completion Services segment. Additionally, strategic partnerships with best-in-class providers of parts, major components and consumables contributed to the sequential improvement in Adjusted EBITDA through increased quality, reliability and the ability to better control and forecast operational costs. In our fracturing business, we redeployed an additional warm-stacked horizontal frac fleet to a dedicated customer in the Haynesville Shale in early June, resulting in approximately 515,000 HHP deployed, consisting of twelve horizontal and three vertical frac fleets. In our wireline and pumping services business, we achieved a substantial increase in activity through new customer relationships, as well as efficiency gains with legacy customers. This enabled us to deploy on average six additional wireline trucks and thirteen additional pumping units over the course of the quarter with strong utilization and pricing levels over an expanded asset base. In our cementing services business, we experienced higher activity levels and deployed on average four additional units into our core West Texas market, which allowed us to capture increased utilization that resulted in improved financial performance. In our coiled tubing services business, we continued to focus on increasing margins and enhancing profitability. As such, we decided to discontinue operations in the Northeast and reallocate those units to South Texas where demand for large diameter coil remains strong and activity levels have continued to increase.

Completion Services Outlook

As we move through the third quarter, we currently expect that our Completion Services segment will continue to experience strong activity levels based on ongoing conversations with customers, combined with the understanding that many of our key customers increased their drilling rig count during the second quarter.

Due to the continued strong near-term outlook, we are currently planning to deploy additional refurbished equipment, as well as new equipment, over the remainder of 2017. To capitalize on visible customer demand in our frac business, we plan to deploy an additional horizontal fleet, consisting of new-build pumps and refurbished ancillary equipment, with a dedicated customer in West Texas in August, as well as another vertical frac fleet comprised of refurbished equipment into South Texas by the end of the third quarter. This will result in us exiting the third quarter with approximately 575,000 HHP deployed, consisting of thirteen horizontal fracturing fleets and four vertical fleets. Additionally, we are currently in negotiations with several operators to deploy a cold stacked horizontal frac fleet by the end of October. The resulting fourteen

-42-

Table of Contents

horizontal fleets together with the four vertical fleets will give us the equivalent of approximately 16 horizontal spreads deployed by year-end. Following that, our remaining fleet re-activations will consist of a combination of warm and cold stacked equipment. We have also ordered another 20 new-build Tier II frac pumps that will be combined with existing process equipment to form an additional horizontal fleet that will be deployed in the first quarter of 2018. These additional pumps will increase our total fleet size to approximately 900,000 HHP.

In our cased-hole solutions services business, we expect to deploy additional wireline trucks and up to six re-purposed stacked frac pumps into service by the end of the third quarter, assuming activity remains strong. We are also allocating capital to redeploy our four remaining warm stacked cementing units into West Texas during the second half of 2017 in order to meet growing customer demand, and we recently placed an order for two large diameter new-build coiled tubing units in order to meet strong demand from multiple customers, both of which we currently expect to have active in early 2018. Additionally, we have continued to evaluate our coiled tubing services line, closing unprofitable facilities and reallocating equipment in order to capture higher margin completion oriented work, and acid and nitrogen workover and maintenance work, in select operating basins. We have and expect to continue to experience increases in activity and pricing in most core basins, such as South Texas, West Texas and the Mid-Continent.

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, and special services, including artificial lift applications and other specialty well site services. The majority of revenue for this segment is generated by our rig services business, and we consider rig services and fluids management to be our core businesses within this segment.

During the second quarter of 2017, our rig services business deployed, on average, approximately 149 workover rigs per workday out of our average fleet of approximately 458 workover rigs. In our fluids management business, we deployed, on average, approximately 651 fluid services trucks per workday and approximately 1,050 frac tanks per workday out of our estimated average fleets of approximately 1,121 trucks and 4,103 frac tanks, respectively. In our fluids management business, we own 29 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. Additionally, in response to the continued competitive landscape, 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 the quarter ended June 30, 2017, revenue from our Well Support Services segment was $96.0 million, representing approximately 24.6% of our total revenue, compared with revenue of $96.3 million for the quarter ended March 31, 2017, which represents an 0.3% quarter-over-quarter decrease. Adjusted EBITDA from this segment for the quarter ended June 30, 2017 was $1.9 million, compared with $3.8 million of Adjusted EBITDA for the quarter ended March 31, 2017.

Management evaluates the operation and performance of our Well Support Services segment and allocates resources primarily based on activity levels, specifically rig and trucking hours, as well as Adjusted EBITDA. The following table presents revenue, rig and trucking hours for our Well Support Services segment for the three months ended June 30, 2017 and 2016 (dollars in thousands):

-43-

Table of Contents



	Successor		Predecessor
	Three Months Ended
	June 30, 2017		June 30, 2016

Revenue
Rig Services	$	54,022	$	44,820
Fluids Management Services	32,141		34,819
Other Well Support Services (includes ESPCT)	9,833		8,093
Total revenue	$	95,996	$	87,732

Adjusted EBITDA	$	1,927	$	4,004

Average active workover rigs	197		191
Total workover rig hours	116,192		99,485

Average fluids management trucks	1,121		1,444
Average active fluids management trucks	651		744
Total fluids management truck hours	328,785		361,788

During the second quarter, both revenue and Adjusted EBITDA decreased sequentially in our Well Support Services segment, primarily due to decreased activity levels in our rig services business and higher overall labor and maintenance expenses. The market for all of our businesses within this segment has remained very competitive with limited ability to increase pricing or activity. Unseasonable warm weather lead to an earlier spring break-up that negatively impacted our Canadian rig services business, which was partially offset by slightly higher pricing and modest activity level increases for our rig services and special services business in certain core operating regions in the United States such as California, West Texas, the Mid-Continent and South Texas. In our fluids management business, utilization and pricing remained under pressure during the quarter primarily due to predatory pricing from certain of our competitors, additional wells shut-in from conventional oil and gas fields and increased competition from continued infrastructure build-out. In addition, we divested our fluid hauling and storage operations in the Northeast, and we will continue to evaluate alternatives to further right-size our fluids management business to maximize profitability.

Well Support Services Outlook

As we move through the third quarter, a period with increased daylight hours, we expect activity levels to modestly improve as we put more workover rigs to work in core basins in the United States. Although average rig services activity during the second quarter was lower compared to the first quarter, we exited the second quarter with our highest number of active rigs working in the past twelve months. In addition, relatively stable commodity prices have encouraged certain of our largest customers to allocate more capital towards well workover and maintenance, which could result in higher overall utilization and enhanced revenue growth, specifically in our rig services business. In our fluids management business, we continue to focus on quality work with core customers and to aggressively manage costs in order to maintain profitability while the market continues to suffer from overall low pricing and stagnant utilization. We have been successful in winning work in many of our core basins, we believe largely due to competitor service quality and safety issues, and we continue to experience pockets of slight pricing improvement in select core operating regions. Nonetheless, our fluids management service line continues to suffer from significant industry overcapacity, an increased number of shut-in wells in conventional oil and gas fields and increased competition from continued infrastructure build-out. Until customers begin allocating significantly more capital towards workover and maintenance of existing wells, we would expect only modest increases in both utilization and pricing within the majority of our Well Support Services segment for the remainder of 2017. Accordingly, we do not expect our Well Support Services results to improve materially over the near term.

Other Services

-44-

Table of Contents

Our Other Services segment contributed $1.9 million of revenue for the three months ended June 30, 2016, representing approximately 0.8% of our total revenue. Adjusted EBITDA from this segment for the three months ended June 30, 2016 was $(0.6) million.

Operating Overview & Strategy

Our results of operations in our core service lines are driven primarily by four interrelated, fluctuating variables: (1) the drilling, 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, 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 products and labor involved in providing our services, and our ability to pass those costs on to our customers; and (4) our activity, or “utilization” levels, and service performance.

Our operating strategy is focused on maintaining high asset utilization levels to maximize revenue generation while controlling cost to gain a competitive advantage and drive returns. We believe that the quality and efficiency of our service execution and aligning with customers who recognize the value that we provide through efficiency gains are central to our efforts to support utilization and grow our business. However, asset utilization is not necessarily indicative of our financial and/or operational performance and should not be given undue reliance. Given 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 the cost of providing those services, among other factors, operating margins can fluctuate widely depending on supply and demand at a given point in the cycle.

Historically, our utilization levels have been highly correlated to U.S. onshore spending by our customers as a group. Generally, as capital spending by our customers increases, 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 could further adversely affect 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.”

Management evaluates the 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. Our management team also monitors asset utilization, among other factors, for purposes of assessing our overall activity levels and customer demand. 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 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. 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 cannot be relied on as indicative of our financial or operating performance. For additional information, please see “Our Reportable Business Segments” in this Part I, Item 2 “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

-45-

Table of Contents

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 the 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 general domestic and international economic conditions, 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, and other factors that are beyond our control.

In light of the above, demand for our services tends to be extremely volatile and cyclical, as 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 and, to a lesser extent, in Western Canada. Our customers’ willingness to undertake such activities and expenditures depends largely upon prevailing industry conditions that are influenced by numerous factors which are beyond our control, including, among other things, current and expected future levels of oil and gas prices and the perceived stability and sustainability of those prices, which, in turn, is driven primarily by the supply of, and demand for, oil and gas. Oil and gas prices, and therefore the level of drilling, completion and workover activity by our customers, historically have been extremely volatile and are expected to continue to be highly volatile.

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 expenditures by our customers adversely affected the demand for our services throughout the severe industry downturn. Our financial and operational performance were significantly impacted, which led to the Chapter 11 Proceeding. Although both crude oil and natural gas prices began to increase modestly and stabilize in late 2016, commodity prices, in general, have remained significantly lower than the industry average experienced 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 thus far in 2017 prices have averaged approximately $50.00 per barrel. Natural gas prices declined significantly in 2009 and have remained depressed relative to pre-2009 levels. Commodity prices continue to be relatively unstable and any declines or perceived sustained weakness impacts the allocation of capital by our customers.

As explained above, sustained weakness in oil and gas prices influences our customers to curtail their operations, reduce their capital expenditures, and request pricing concessions to reduce their operating costs. The demand for drilling, completion and workover services is driven by available investment capital for such activities and in a lower oil and gas price environment, demand for service and maintenance generally decreases as oil and gas producers decrease their activity and 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. A prolonged low level of customer activity, such as we experienced in 2015 and through most of 2016, could adversely affect our financial condition and results of operations.

Competition and Demand for Our Services

We operate in highly competitive areas of the oilfield services industry with significant potential for excess capacity. Completion and well servicing equipment can be moved from one region to another in response to changes in levels of activity and market conditions, which may result in an oversupply of such equipment in any particular area. Utilization and pricing for our services have in the past been negatively affected by increases in supply relative to demand in our core operating areas and geographic markets.

-46-

Table of Contents

Additionally, the demand for our services depends primarily on the level of spending by oil and gas companies for drilling, completion and production activities, which is affected by short-term and long-term trends in oil and natural gas prices and numerous other factors over which we have no control. 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 the level of drilling, completion and production activity and capital expenditures by our customers, adversely affected the demand for our services. This, in turn, negatively impacted our ability to maintain adequate utilization of our asset base and to negotiate pricing at levels generating sufficient margins. Moreover, the impact to our financial and operational performance ultimately led to the Chapter 11 Proceeding.

Our revenues and earnings 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. Pressure on pricing for our services, including due to competition and industry and/or economic conditions, may impact, among other things, our ability to maintain utilization 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.

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 our Completion Services include Halliburton, Schlumberger, Keane Group, RPC, Inc., FTS International, Inc. (formerly known as Frac Tech Services), Basic Energy Services, Superior Energy Services, CalFrac Well Services, a significant number of regional, predominantly private businesses, and to a smaller extent, both Weatherford International and Baker Hughes, both of which have recently announced plans to exit the hydraulic fracturing business. Our major competitors for our Well Support Services include Key Energy Services, Basic Energy Services, Superior Energy Services, Precision, Forbes and Pioneer 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 most 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 this downturn, our utilization and pricing levels were also negatively impacted by predatory pricing from certain large competitors, who elected to operate at negative margins for these 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 in 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 volume, high efficiency customers with service intensive, 24-hour work, which is where we believe we can differentiate our services from our competitors.

Current Market Conditions and Outlook

The challenging market conditions experienced from late 2014 through most of 2016 began to abate towards the end of 2016 as commodity prices began to stabilize and customers began re-initiating their drilling and completion programs. As we entered 2017, we experienced increasing utilization levels in our Completion Services segment as our customers accelerated drilling and completion activity to take advantage of higher overall commodity prices. In many cases, we were able to increase pricing across our core Completion Services business, largely due to a lack of available service capacity in select core operating basins. The continued growth in the North American land drilling rig count coupled with a shortage of available fracturing equipment over the second quarter resulted in higher overall utilization and pricing levels across our Completion Services business.

In our Well Support Services segment, we also experienced some improvement in market conditions entering into 2017, as customers began to allocate more capital towards well maintenance and workover activities with the stabilization in commodity prices. However, even with the increased activity levels experienced early in the year, the operating environment

-47-

Table of Contents

has remained highly competitive. In the second quarter, we experienced a decline in activity in our rig services business and utilization and pricing for our fluids management business remained under pressure due to extremely competitive pricing, additional wells shut-in from conventional oil and gas fields and continued infrastructure build-out. We continue to evaluate alternatives to further rightsize these businesses with current market conditions, such as our recent decision to divest of our Northeast fluids hauling and storage operations.

We are cautiously optimistic about the continued improvement in completion activity over the remainder of 2017. As long as macroeconomic conditions and commodity prices remain stable, we would expect steady levels of activity from the majority of our customer base for the remainder of 2017, which should result in continued operational and financial improvement in our Completion Services segment. In our Well Support Services Segment, until customers begin allocating significantly more capital towards workover and maintenance of existing wells, we would expect only modest increases in both utilization and pricing within the majority of our segment for the remainder of 2017.

We are actively monitoring the market and managing our business in line with demand for services, and we will make adjustments as necessary to effectively respond to changes in market conditions. We are taking a measured approach to asset deployment, balancing our view of customer demand with an acute focus on generating positive returns. Our top priorities remain to drive revenue by maximizing utilization, improve margins through cost controls, protect and grow market share by focusing on the quality and efficiency of our service execution and ensure we are strategically positioned to capitalize on future market improvement.

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

As a result of our emergence from the Chapter 11 Proceeding, the first quarter 2017 financial results have been separately presented under the label "Successor" for 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.

Results for the Three Months Ended June 30, 2017 Compared to the Three Months Ended June 30, 2016

The following table summarizes the change in our results of operations for the three months ended June 30, 2017 when compared to the three months ended June 30, 2016 (in thousands):

-48-

Table of Contents



	Successor			Predecessor
	Three Months Ended June 30, 2017			Three Months Ended June 30, 2016			$ Change
Completion Services:
Revenue	$	294,147		$	135,579		$	158,568
Operating income (loss)	$	28,886		$	(101,663	)	$	130,549

Well Support Services:
Revenue	$	95,996		$	87,732		$	8,264
Operating loss	$	(7,900	)	$	(12,095	)	$	4,195

Other Services:
Revenue	$	—		$	1,857		$	(1,857	)
Operating loss	$	—		$	(21,973	)	$	21,973

Corporate / Elimination:
Revenue	$	—		$	—		$	—
Operating loss	$	(34,230	)	$	(46,706	)	$	12,476

Combined:
Revenue	$	390,143		$	225,168		$	164,975

Costs and expenses:
Direct costs	310,473			229,771			80,702
Selling, general and administrative expenses	61,165			71,341			(10,176		)
Research and development	2,052			1,786			266
Depreciation and amortization	32,833			54,283			(21,450		)
Impairment expense	—			48,712			(48,712		)
(Gain) loss on disposal of assets	(3,136		)	1,712			(4,848		)
Operating loss	(13,244		)	(182,437		)	169,193
Other income (expense):
Interest expense, net	(414		)	(121,934		)	121,520
Other income (expense), net	(1,456		)	2,003			(3,459		)
Total other income (expense)	(1,870		)	(119,931		)	118,061
Loss before income taxes	(15,114		)	(302,368		)	287,254

Income tax benefit	(2,393		)	(11,252		)	8,859
Net loss	$	(12,721	)	$	(291,116	)	$	278,395

Revenue

Revenue increased $165.0 million, or 73.3%, to $390.1 million for the three months ended June 30, 2017, as compared to $225.2 million for the three months ended June 30, 2016. The increase in revenue was primarily due to (i) an increase of $158.6 million in our Completion Services segment as a result of the continued growth in the North American land drilling rig count coupled with a shortage of available fracturing equipment yielding higher overall utilization and pricing levels across our service lines, (ii) an increase of $8.3 million in our Well Support Services segment as a result of increased activity levels coupled with modest pricing improvement in the West Texas region and (iii) a decrease of $1.9 million in our Other Services segment as a result of the segment being divested subsequent to June 30, 2016.

Direct Costs

-49-

Table of Contents

Direct costs increased $80.7 million, to $310.5 million for the three months ended June 30, 2017, compared to $229.8 million for the three months ended June 30, 2016. The increase in direct costs was primarily due to the increased revenue primarily from our Completion Services segment, partially offset by inventory write-downs in the corresponding prior year period.

Selling, General and Administrative Expenses (“SG&A”) and Research and Development Expense (“R&D”)

SG&A decreased $10.2 million, or 14.3%, to $61.2 million for the three months ended June 30, 2017, as compared to $71.3 million for the three months ended June 30, 2016. The decrease in SG&A was primarily due to (i) an $8.6 million reduction in severance costs as a result of headcount reductions during the corresponding prior year period, (ii) a $7.6 million reduction in costs related to our restructuring activities as a result of the debt covenant violation leading up to the Chapter 11 Proceeding during the corresponding prior year period, (iii) a $3.1 million reduction in integration related costs incurred in the corresponding prior year period primarily related to the planned implementation of a new computer system that provides financial reporting, inventory management and fixed asset management capabilities (the "new ERP system") and (iv) a $0.2 million decrease in other general and administrative expenses, partially offset by a $9.3 million increase in compensation expense primarily as a result of (i) significant increases in operating performance throughout the first half of 2017 and (ii) the full impact of the reinstatement of previously reduced compensation programs during the first quarter of 2017.

We also incurred $2.1 million in R&D for the three months ended June 30, 2017 as compared to $1.8 million for the corresponding prior year period. The increase in R&D is primarily due to increased spending on select key technologies that are providing our businesses with a competitive advantage by enhancing our operational capabilities and reducing our overall cost structure.

Depreciation and Amortization Expense (“D&A”)

D&A decreased $21.5 million, or 39.5%, to $32.8 million for the three months ended June 30, 2017, as compared to $54.3 million for the three months ended June 30, 2016. The decrease in D&A was primarily the result of a lower value of the asset base as a result of the estimated fresh start adjustments to the Company's property, plant and equipment (PP&E) and other intangible assets.

Impairment Expense

Due to the severe downturn in the oil and gas industry and the resulting sustained weakness in demand for our services, we determined that it was necessary to test goodwill for impairment and to test property, plant and equipment ("PP&E") and other intangible assets for recoverability throughout 2016.

Impairment expense for the three months ended June 30, 2016 was $48.7 million and primarily consisted of $45.3 million related to PP&E within each of our Completion Services segment, Well Support Services segment and Other Services segment and $3.4 million related to intangible assets within each of our Completion Services segment, Well Support Services segment, and Other Services segment.

Interest Expense

Interest expense was $0.4 million for the three months ended June 30, 2017, which decreased $121.5 million from $121.9 million for the corresponding prior year period. The decrease is primarily due to the settlement of all outstanding borrowings of the Predecessor in accordance with the Restructuring Plan in addition to $91.9 million of interest expense in the corresponding prior year period related to accelerated amortization of original issue discount and deferred financing costs, which were fully amortized as of June 30, 2016 as a result of the Restructuring Support agreement.

Income Taxes

We recorded a tax benefit of $2.4 million for the three months ended June 30, 2017, at an effective rate of 15.8%, compared to a tax benefit of $11.3 million for the comparable prior year period, at an effective rate of 3.7%. For the three months ended June 30, 2017, before the effect of additional allowed refund claims, we recorded income taxes at an estimated effective tax rate of approximately 1.0%. The decrease in the effective tax rate, and the resulting effective tax rate below the expected statutory rate, was primarily due to the existence of our valuation allowance applied against certain deferred tax assets, including net operating loss carryforwards.

Results for the Six Months Ended June 30, 2017 Compared to the Six Months Ended June 30, 2016

-50-

Table of Contents

The following table summarizes the change in our results of operations for the six months ended June 30, 2017 when compared to the six months ended June 30, 2016 (in thousands):



	Successor			Predecessor
	Six Months Ended June 30, 2017			Six Months Ended June 30, 2016			$ Change
Completion Services:
Revenue	$	512,075		$	306,406		$	205,669
Operating income (loss)	$	39,091		$	(220,732	)	$	259,823

Well Support Services:
Revenue	$	192,262		$	184,684		$	7,578
Operating loss	$	(16,133	)	$	(349,934	)	$	333,801

Other Services:
Revenue	$	—		$	3,693		$	(3,693	)
Operating loss	$	—		$	(27,542	)	$	27,542

Corporate / Elimination:
Revenue	$	—		$	—		$	—
Operating loss	$	(72,610	)	$	(84,644	)	$	12,034

Combined:
Revenue	$	704,337		$	494,783		$	209,554

Costs and expenses:
Direct costs	572,216			491,536			80,680
Selling, general and administrative expenses	123,257			133,380			(10,123		)
Research and development	3,269			4,163			(894		)
Depreciation and amortization	64,439			113,236			(48,797		)
Impairment expense	—			430,406			(430,406		)
(Gain) loss on disposal of assets	(9,192		)	4,914			(14,106		)
Operating loss	(49,652		)	(682,852		)	633,200
Other income (expense):
Interest expense, net	(1,105		)	(147,401		)	146,296
Other income (expense), net	106			5,325			(5,219		)
Total other income (expense)	(999		)	(142,076		)	141,077
Loss before income taxes	(50,651		)	(824,928		)	774,277

Income tax benefit	(5,629		)	(105,399		)	99,770
Net loss	$	(45,022	)	$	(719,529	)	$	674,507

Revenue

Revenue increased $209.6 million, or 42.4%, to $704.3 million for the six months ended June 30, 2017, as compared to $494.8 million for the corresponding prior year period. The increase in revenue was primarily due to (i) an increase of $205.7 million in revenue in our Completion Services segment as a result of the continued growth in the North American land drilling rig count coupled with a shortage of available fracturing equipment yielding higher overall utilization and pricing levels across our service lines, (ii) an increase of $7.6 million in our Well Support Services segment as a result of

-51-

Table of Contents

increased activity levels in many of our core operating basins and (iii) a decrease of $3.7 million in our Other Services segment as a result of the segment being divested subsequent to June 30, 2016.

Direct Costs

Direct costs increased $80.7 million, or 16.4%, to $572.2 million for the six months ended June 30, 2017, compared to $491.5 million for the corresponding prior year period. The increase in direct costs was primarily due to the increased revenue, primarily from our Completion Services segment, partially offset by inventory write-downs.

Selling, General and Administrative Expenses (“SG&A”) and Research and Development Expense (“R&D”)

SG&A decreased $10.1 million, or 7.6%, to $123.3 million for the six months ended June 30, 2017, as compared to $133.4 million for the corresponding prior year period. The decrease in SG&A was primarily due to (i) an $8.8 million reduction in severance costs as a result of headcount reductions in the corresponding prior year period, (ii) a $7.8 million reduction in costs related to our restructuring activities as a result of the debt covenant violation leading up to the Chapter 11 Proceeding during the corresponding prior year period, (iii) a $6.1 million reduction in integration related costs incurred in the corresponding prior year period primarily related to the planned implementation of the new ERP system and (iv) a $2.2 million reduction in insurance expense primarily due to our incurred but not reported ("IBNR") accrual for the period, partially offset by a $14.4 million increase in compensation expense primarily as a result of (i) significant increases in operating performance throughout the first half of 2017 and (ii) the reinstatement of certain previously reduced compensation programs during the first half of 2017, and a $0.4 million increase in other general and administrative expenses.

We also incurred $3.3 million in R&D for the six months ended June 30, 2017, as compared to $4.2 million for the corresponding prior year period. The decrease in R&D was primarily due to limiting our investments to those key technologies that are providing our businesses with a competitive advantage by enhancing our operational capabilities and reducing our overall cost structure.

Depreciation and Amortization Expense (“D&A”)

D&A decreased $48.8 million, or 43.1%, to $64.4 million for the six months ended June 30, 2017, as compared to $113.2 million for the corresponding prior year period. The decrease in D&A was primarily the result of a lower value of the asset base as a result of the estimated fresh start adjustments to the Company's PP&E and other intangible assets.

Impairment Expense

Due to the severe downturn in the oil and gas industry and the resulting sustained weakness in demand for our services, we determined that it was necessary to test goodwill for impairment and to test PP&E and other intangible assets for recoverability throughout 2016.

Impairment expense for the six months ended June 30, 2016 was $430.4 million and consisted of $314.3 million of goodwill impairment related to impairment of all remaining goodwill associated with our Well Support Services segment, along with $55.0 million related to other intangible assets and $61.1 million related to PP&E within each of our Completion Services segment, Well Support Services segment and Other Services segment.

Interest Expense

Interest expense was $1.1 million for the six months ended June 30, 2017, which decreased $146.3 million from $147.4 million in the corresponding prior year period. The decrease is primarily due to the settlement of all outstanding borrowings of the Predecessor in accordance with the Restructuring Plan in addition to the prior year $91.9 million of accelerated amortization of original issue discount and deferred financing costs, fully amortized as of June 30, 2016 as a result of the Restructuring Support agreement

Income Taxes

We recorded a tax benefit of $5.6 million for the six months ended June 30, 2017, at an effective rate of 11.1%, compared to a tax benefit of $105.4 million for the comparable prior year period, at an effective rate of 12.8%. For the six months ended June 30, 2017, before the effect of unrecognized tax positions and additional allowed refund claims, we recorded income taxes at an estimated tax rate of approximately 1.0%. The decrease in the effective tax rate was primarily due to valuation allowances applied against certain deferred tax assets, including net operating loss carryforwards.

-52-

Table of Contents

Liquidity and Capital Resources

Sources of Liquidity and Capital Resources

Our primary uses of cash are for operating costs and expenditures and capital 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 requirements consist primarily of:


•	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


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

In addition, during prior periods, a significant amount of our cash flow was used to service our significant indebtedness as a result of the Nabors Merger. However, as a result of the Chapter 11 Proceeding, substantially all of our debt was discharged and we expect that interest expense will be a smaller component of our expenses in the near term.

As of June 30, 2017, we had a cash balance of $252.8 million and no borrowings drawn on our Amended Credit Facility (as defined below), which had borrowing capacity of $173.4 million resulting in total liquidity of $426.2 million. Under the terms of our Amended Credit Facility, the borrowing base is subject to monthly adjustments based on current levels of accounts receivable and inventory. Our current cash balance is $243.1 million, and our current borrowing capacity is $178.4 million, resulting in $421.5 million of total liquidity.

Capital expenditures totaled $72.5 million during the first half of 2017, primarily pertaining to our deployed equipment and the refurbishment of existing stacked equipment in preparation for redeployment. We currently expect 2017 capital expenditures to total between $200.0 million and $210.0 million, compared to $57.9 million in 2016. In response to persistently challenging industry conditions, we significantly scaled back our 2016 capital expenditure plan, limiting it to the maintenance of our active, deployed equipment. Based on current customer demand, and assuming current market conditions remain stable, we currently expect that the majority of our 2017 capital expenditures will include the refurbishment and related reactivation costs of existing stacked equipment in preparation for redeployment, as well as growth capital expenditures for the purchase of new equipment across our core service lines. 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.

With the growing North American drilling rig count, relatively stable commodity prices, and the continued shortages of available completion services equipment, we are particularly focused on redeploying our stacked frac fleets. The recent industry cycle has provided an opportunity to upgrade our equipment concurrent with our reactivation efforts and achieve standardization across our frac fleet, which among other benefits, is expected to increase the operating life of the equipment and lower the overall cost of ownership. During the second quarter of 2017, we deployed an additional refurbished fleet of 40,000 HHP, and we currently plan to deploy an additional horizontal fleet and an additional vertical fleet totaling 60,000 HHP in the third quarter of 2017. Additionally, we plan to deploy the remainder of our 75,000 warm stacked HHP and 230,000 cold stacked HHP over the course of 2017 and 2018. We currently believe the cost of refurbishing our additional warm stacked HHP will range between $250,000 to $350,000 per pump and our cold stacked equipment will range between $500,000 and $600,000 per pump. With respect to some of the older cold stacked fleets, in addition to the pump refurbishment costs, we expect to incur additional costs for ancillary equipment necessary for redeployment. Our typical horizontal fleet size consists of 20 pumps and our typical vertical fleet size consists of 10 pumps. Additionally, we recently placed an order for 20 new-build pumps, which will be delivered in the first quarter of 2018. These pumps will increase our total HHP capacity to approximately 900,000 HHP, and we expect to combine them with existing ancillary equipment to form an additional horizontal fleet.

Our primary sources of liquidity have historically included cash flows from operations, proceeds from public offerings of common stock and borrowings under debt facilities. Future cash flows are subject to a number of variables, and are highly dependent on the drilling, completion and production activity by our customers, which in turn 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 the market challenges within our industry.

On January 6, 2017, we entered into a revolving credit and security agreement (the “New Credit Facility”) with PNC Bank, National Association, as administrative agent (the “Agent”). We subsequently amended and restated the New

-53-

Table of Contents

Credit Facility in full pursuant to an amended and restated revolving credit and security agreement (the “Amended Credit Facility”) dated May 4, 2017, with the Agent and the lenders party thereto. We currently have $178.4 million of available borrowing capacity under our Amended Credit Facility after taking into consideration our current outstanding letters of credit of approximately $20.7 million. For additional information about the Amended Credit Facility, please see “Description of our Indebtedness” below and Note 4 - Debt in Part I, Item 1 “Financial Statements” of this Quarterly Report.

On April 12, 2017, we consummated an underwritten public offering of an aggregate 8,050,000 shares of our common stock at public offering price of $32.50 per share, of which 7,050,000 shares were offered by us and 1,000,000 shares were offered by the selling stockholder. We received approximately $216.2 million in net proceeds after deducting underwriting discounts and commissions and other estimated expenses of the offering payable by us. We are using the net proceeds to us from the offering for general corporate purposes, including to fund our 2017 capital expenditure and growth initiatives. We did not receive any of the proceeds from the sale of shares of common stock by the selling stockholder.

Based on our existing operating performance, we currently believe that our cash flows from operations and existing capital 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):



	Successor			Predecessor
	Six Months Ended June 30, 2017			Six Months Ended June 30, 2016
Cash provided by (used in):
Operating activities	$	(96,854	)	$	(76,020	)
Investing activities	(41,365		)	(9,511		)
Financing activities	210,587			153,204
Effect of exchange rate on cash	(855		)	(2,803		)
Change in cash and cash equivalents	$	71,513		$	64,870

Cash Provided by Operating Activities

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 $138.8 million of (i) increased investment in working capital (accounts receivable, inventory and accounts payable) as a result of the increase in the demand for our completion services and the resulting increase in revenue and direct costs for the first six months of 2017 and (ii) 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, inventory and accounts payable.

Net cash used in operating activities was $76.0 million for the six months ended June 30, 2016. The use of cash was primarily related to net loss of $719.5 million and adjustments for non-cash items of $575.6 million, partially offset by (i) cash inflows of $57.5 million due to a decrease in our investment in working capital (accounts receivable, inventory, accounts payable and accrued expenses) as a result of the decrease in the demand for our services and the resulting decrease in revenue and direct costs during the first six months of 2016 and (ii) positive changes in operating assets and liabilities, excluding accounts receivable, inventory, accounts payable and accrued expenses.

Cash Used in Investing Activities

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 primarily pertaining to the refurbishment of stacked equipment and the construction of new-build Frac pumps and refurbished ancillary equipment, partially offset by (i) $27.1 million of proceeds from the divestiture of our non-core business lines previously reported under our Other Services reportable segment and (ii) $4.0 million of proceeds from the disposal of property, plant and equipment.

-54-

Table of Contents

Net cash used in investing activities was $9.5 million for the six months ended June 30, 2016. The use of cash was primarily related to (i) $36.4 million of capital expenditures primarily pertaining to the new ERP system and to costs incurred to extend the useful lives of our existing equipment and (ii) $1.4 million of payments related to the acquisition of our artificial lift service line, partially offset by $28.8 million of proceeds from the disposal of property, plant and equipment.

Cash Provided by Financing Activities

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, partially offset by (i) $3.9 million of employee tax withholding on restricted stock vesting and (ii) $1.5 million of cash paid for financing costs related to our Amended Credit Facility.

Net cash provided by financing activities was $153.2 million for the six months ended June 30, 2016. The cash provided was primarily related to $174.0 million in proceeds from the Predecessor's revolving credit facility, partially offset by (i) $13.3 million in payments on the Predecessor's revolving credit facility and term debt, (ii) $5.6 million of payments for excess tax expense from share-based compensation and (iii) $1.5 million in payments related to capital lease obligations.

Description of our Indebtedness

The Successor and certain of its subsidiaries (the “Borrowers”) entered into the New Credit Facility on the Plan Effective Date, and on May 4, 2017 entered into the Amended Credit Facility.

The Amended Credit Facility allows the 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 is based upon the value of the Borrowers’ accounts receivable and inventory, subject to eligibility criteria and customary reserves which may be modified in the Agent’s permitted discretion.

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

At the Borrowers’ election, interest on borrowings under the Amended Credit Facility will be 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 will be subject to a monthly step-up of 0.25% in the event that average excess availability under the Amended Credit Facility is 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 Amended Credit Facility equal to or greater than 62.5% of the total commitment. 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. The Borrowers will also be required to pay a fee on the unused portion of the Amended Credit Facility equal to (i) 0.75% in the event that utilization is less than 25.0% of the total commitment, (ii) 0.50% in the event that utilization is 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 is equal to or greater than 50% of the total commitment.

The Amended 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 if, as of any month-end, liquidity is less than $40.0 million.

-55-

Table of Contents

Other Matters

Contractual Obligations

Other than as disclosed in Note 4 - Debt in Part I, Item 1 “Financial Statements” of this Quarterly Report, our contractual obligations at June 30, 2017 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 2016 Annual Report. Specifically, in accordance with the Restructuring Plan, on the Plan Effective Date, the Company repaid all amounts outstanding under the DIP Facility with the proceeds from the Rights Offering and the DIP Facility was canceled and discharged.

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, 2017.

Recent Accounting Pronouncements

In May 2014, the Financial Accounting Standards Board ("FASB") issued a comprehensive new revenue recognition standard, Accounting Standards Update ("ASU") No. 2014-09, Revenue from Contracts with Customers ("ASU 2014-09") that will supersede existing revenue recognition guidance under U.S. GAAP. In August 2015, the FASB issued an accounting standards update for a one-year deferral of the revenue recognition standard's effective date for all entities, which changed the effectiveness to annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. The core principle of the new guidance is that a company should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. The standard creates a five-step model that requires companies to exercise judgment when considering the terms of a contract and all relevant facts and circumstances. The standard allows for several transition methods: (a) a full retrospective adoption in which the standard is applied to all of the periods presented, or (b) a modified retrospective adoption in which the standard is applied only to the most current period presented in the financial statements, including additional disclosures of the standard’s application impact to individual financial statement line items. We will adopt this new accounting standard on January 1, 2018 and upon adoption, we will incorporate the modified retrospective approach as our transition method that will result in a cumulative effect adjustment as of January 1, 2018. We are currently determining the impacts of the new standard on our contract portfolio. Our approach includes performing a detailed review of key contracts representative of our different businesses and comparing historical accounting policies and practices to the new standard. Since our services are primarily short-term in nature, our assessment at this stage is that we do not expect the new revenue recognition standard will have a material impact on our consolidated financial statements upon adoption.

In July 2015, the FASB issued ASU No. 2015-11, Simplifying the Measurement of Inventory ("ASU 2015-11"), which changes the measurement principle for inventory from the lower of cost or market to lower of cost and net realizable value. ASU 2015-11 is part of the FASB’s simplification initiative and applies to entities that measure inventory using a method other than last-in, first-out ("LIFO") or the retail inventory method. The guidance will require prospective application at the beginning of our first quarter of fiscal 2018, but permits adoption in an earlier period. We do not expect this ASU to have a material impact on our consolidated financial statements.

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 are currently evaluating the impact of adopting this new accounting standard on our results of operations and financial position.

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

-56-

Table of Contents

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 are currently evaluating the impact of adopting this new accounting standard on our results of operations and financial position.

-57-

Table of Contents

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

As of June 30, 2017, 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 2016 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, 2017.

Changes in Internal Controls Over Financial Reporting.

No changes in our system of internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) occurred during the quarterly period ended June 30, 2017 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

-58-

Table of Contents

PART II – OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

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

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

There is a pending criminal investigation led by the United States Attorney’s Office for the District of North Dakota in connection with a fatality that occurred at a C&P Business facility in Williston, North Dakota on October 3, 2014 prior to the Predecessor’s acquisition of the C&P Business in the Nabors Merger. We are cooperating fully with the investigation, and expect to continue to do so. At this time, the Company cannot predict the outcome of the investigation.

Shareholder Litigation

In July 2014, following the announcement that Old C&J, Nabors, and the Predecessor had entered into the Merger Agreement, a putative class action lawsuit was filed by a purported shareholder of Old C&J challenging the Merger. The lawsuit is styled City of Miami General Employees’ and Sanitation Employees’ Retirement Trust, et al. (“Plaintiff”) v. Comstock, et al.; C.A. No. 9980-CB, in the Court of Chancery of the State of Delaware, filed on July 30, 2014 (the “Shareholder Litigation”). Plaintiff generally alleged that the board of directors for Old C&J breached fiduciary duties of loyalty, due care, good faith, candor and independence by allegedly approving the Merger Agreement at an unfair price and through an unfair process. Plaintiff alleged that the Old C&J board directors, or certain of them, (i) failed to fully inform themselves of the market value of Old C&J, or maximize its value and obtain the best price reasonably available for Old C&J, (ii) acted in bad faith and for improper motives, (iii) erected barriers to discourage other strategic alternatives and (iv) put their personal interests ahead of the interests of Old C&J shareholders. The Shareholder Litigation further alleged that Old C&J, Nabors and the Predecessor aided and abetted the alleged breaches of fiduciary duties by the Old C&J board of directors.

On October 29, 2015, Plaintiff filed an amended complaint naming additional defendants and generally alleging, in addition to the allegations described above, that (i) the special committee of the Old C&J board of directors and its advisors improperly conducted a court-ordered solicitation process that the Delaware Supreme Court vacated and (ii) the proxy statement filed in connection with the Merger contains alleged misrepresentations and omits allegedly material information concerning the Merger and court-ordered solicitation process. The Shareholder Litigation asserted, in addition to the claims described above, claims for breach of fiduciary duty and aiding and abetting breach of fiduciary duty against the special committee of the Old C&J board of directors, its financial advisor Morgan Stanley, and certain employees of Old C&J. Following the death of Josh Comstock, our founder and former Chief Executive Officer and Chairman of the Board of Directors, Plaintiff substituted the executor of Mr. Comstock’s estate in place of Mr. Comstock as a defendant in the Shareholder Litigation.

The defendants in the Shareholder Litigation filed motions to dismiss the amended complaint. On August 24, 2016, the Court of Chancery granted defendants’ motions and dismissed the Shareholder Litigation in its entirety with prejudice. On September 22, 2016, Plaintiff filed a Notice of Appeal to the Delaware Supreme Court, appealing the dismissal of the Shareholder Litigation. On March 23, 2017, the Delaware Supreme Court affirmed the dismissal with prejudice of the Shareholder Litigation.

On April 6, 2017, Plaintiff filed a motion in the Court of Chancery seeking an award of fees and costs on the basis that Plaintiff allegedly conferred a benefit on Old C&J stockholders (the “Fee Motion”). On April 11, 2017, counsel for defendants filed a letter requesting the release of a cash bond posted by Plaintiff in fall of 2014 and currently held by the Court of Chancery (the “Bond Request”). Plaintiff filed its opening brief in support of its Fee Motion, as well as its brief in opposition to the Bond Request on July 19, 2017. Briefing on the Fee Motion will conclude on August 28, 2017, and briefing on the Bond Request is currently scheduled to conclude on August 4, 2017. The Court will hear both the Bond Request and Fee Motion on the same day, but a hearing has not yet been scheduled.

We cannot predict the outcome of the Fee Motion, the Bond Request, or any lawsuit that might be filed, nor can we predict the amount of time and expense that will be required to resolve the Fee Motion or the Bond Request. We believe the Fee Motion and Plaintiff's opposition to the Bond Request are without merit and we intend to defend against them vigorously.

ITEM 1A. RISK FACTORS

-59-

Table of Contents

In addition to the information set forth in this Quarterly Report, including under the section titled “Cautionary Note Regarding Forward-Looking Statements,” in Part I, Item 1 “Financial Information,” you should carefully consider the information set forth in Item 1A “Risk Factors” in our 2016 Annual Report and our Quarterly Report on Form 10-Q for the fiscal quarter ended March 31, 2017, each of 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

None.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

ITEM 5. OTHER INFORMATION

None.

-60-

Table of Contents

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.

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		Bylaws of C&J Energy Services, Inc. (incorporated by reference to Exhibit 3.2 to the Registrant’s Current Report on Form 8-K filed on January 6, 2017(File No. 000-55404)).
10.1		Amended and Restated Revolving Credit and Security Agreement, dated as of May 4, 2017, by and among C&J Energy Services, Inc., the lenders party thereto and PNC Bank, National Association, as administrative agent. (incorporated by reference to Exhibit 10.2 to the Registrant's Quarterly Report on Form 10-Q filed on May 10, 2017 (File No. 001-38023))
10.2		Employment Agreement by and between C&J Energy Services, Inc. and Michael Galvan (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed on May 5, 2017 (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.

-61-

Table of Contents

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 9, 2017	By:	/s/ Donald J. Gawick
			Donald J. Gawick
			Chief Executive Officer, President and Director
			(Principal Executive Officer)

		By:	/s/ Mark C. Cashiola
			Mark C. Cashiola
			Chief Financial Officer
			(Principal Financial Officer)

-62-

Table of Contents

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		Bylaws of C&J Energy Services, Inc. (incorporated by reference to Exhibit 3.2 to the Registrant’s Current Report on Form 8-K filed on January 6, 2017(File No. 000-55404)).
10.1		Amended and Restated Revolving Credit and Security Agreement, dated as of May 4, 2017, by and among C&J Energy Services, Inc., the lenders party thereto and PNC Bank, National Association, as administrative agent. (incorporated by reference to Exhibit 10.2 to the Registrant's Quarterly Report on Form 10-Q filed on May 10, 2017 (File No. 001-38023))
10.2		Employment Agreement by and between C&J Energy Services, Inc. and Michael Galvan (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed on May 5, 2017 (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.

-63-

C&J Energy Services, Inc. - FORM 10-Q - August 9, 2017

Attached files

C&J Energy Services, Inc. Reports