Quarterly Report (10-q)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(Mark One)



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

For the quarterly period ended June 30, 2019



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

For the transition period from to

Commission File Number: 001-38383

Quintana Energy Services Inc.

(Exact name of registrant as specified in its charter)




Delaware		82-1221944
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

1415 Louisiana Street, Suite 2900

Houston, TX 77002

(832) 518-4094

(Address, including zip code, and telephone number, including area code, of principal executive offices of registrant)



Securities registered pursuant to 12(b) of the Securities Exchange Act of 1934:
Title of each class	Trading Symbol(s)	Name of each exchange on which registered
Common stock, par value $0.01 per share	QES	New York Stock Exchange

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 every Interactive Data File required to be submitted 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 such files). Yes ý No ☐

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



Large accelerated filer	☐	Accelerated filer	☐

Non-accelerated filer	ý	Smaller reporting company	ý

		Emerging growth company	ý

If an emerging growth company, indicate 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. ý

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

The number of shares of the registrant’s common stock, par value $0.01 per share, outstanding at August 1, 2019, was 33,503,556.

QUINTANA ENERGY SERVICES INC.

FORM 10-Q

TABLE OF CONTENTS




PART I - FINANACIAL INFORMATION		1
	Item 1. Financial Statements	1
	Condensed Consolidated Balance Sheets (Unaudited) as of June 30, 2019 and December 31, 2018	1
	Condensed Consolidated Statements of Operations (Unaudited) for the three and six months ended June 30, 2019 and 2018	2
	Condensed Consolidated Statement of Shareholders Equity (Unaudited) for the three and six months ended June 30, 2019 and 2018	3
	Condensed Consolidated Statements of Cash Flows (Unaudited) for the six months ended June 30, 2019 and 2018	4
	Notes to Condensed Consolidated Financial Statements (Unaudited)	5
	Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	21
	Item 3. Quantitative and Qualitative Disclosures About Market Risk	35
	Item 4. Controls and Procedures	36
PART II - OTHER INFORMATION		36
	Item 1. Legal Proceedings	36
	Item 1A. Risk Factors	36
	Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	36
	Item 3. Defaults Upon Senior Securities	37
	Item 4. Mine Safety Disclosures	37
	Item 5. Other Information	37
	Item 6. Exhibits	37
SIGNATURES		38

PART I



Item 1.	Financial Statements

Quintana Energy Services Inc.

Condensed Consolidated Balance Sheets

( in thousands of U.S. dollars, except per share and share amounts )

(Unaudited)



	June 30, 2019			December 31, 2018
ASSETS
Current assets:
Cash and cash equivalents	$	16,583		$	13,804
Accounts receivable, net of allowance of $1,726 and $1,841	84,753			101,620
Unbilled receivables	8,131			13,766
Inventories (Note 2)	25,005			23,464
Prepaid expenses and other current assets	5,165			7,481
Total current assets	139,637			160,135
Property, plant and equipment, net	156,577			153,878
Operating lease right-of-use asset (Note 5)	16,208			—
Intangible assets, net	8,112			9,019
Other assets	1,333			1,517
Total assets	$	321,867		$	324,549
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	40,665		$	51,568
Accrued liabilities (Note 3)	32,599			37,533
Other current liabilities	8,127			422
Total current liabilities	81,391			89,523
Long-term debt (Note 4)	35,000			29,500
Long-term operating lease liabilities (Note 5)	10,844			—
Long-term finance lease liabilities (Note 5)	9,222			3,451
Deferred tax liability	232			130
Other long-term liabilities	18			125
Total liabilities	136,707			122,729
Commitments and contingencies (Note 8)
Shareholders’ equity:
Preferred shares, $0.01 par value, 10,000,000 authorized; none issued and outstanding	—			—
Common shares, $0.01 par value, 150,000,000 authorized; 34,382,599 issued; 33,705,148 outstanding	350			344
Additional paid-in-capital	354,517			349,080
Treasury shares, at cost, 677,451 and 232,892 common shares	(3,783		)	(1,821		)
Accumulated deficit	(165,924		)	(145,783		)
Total shareholders’ equity	185,160			201,820
Total liabilities and shareholders’ equity	$	321,867		$	324,549

The accompanying notes are an integral part of these condensed consolidated financial statements.

Quintana Energy Services Inc.

Condensed Consolidated Statements of Operations

( in thousands of U.S. dollars and shares, except per share amounts )

(Unaudited)



	Three Months Ended						Six Months Ended
	June 30, 2019			June 30, 2018			June 30, 2019			June 30, 2018
Revenues:	$	125,627		$	152,536		$	267,292		$	293,804
Costs and expenses:
Direct operating costs	109,075			124,592			230,626			240,689
General and administrative	13,862			14,489			29,571			34,802
Depreciation and amortization	13,116			11,155			25,556			22,233
Gain on disposition of assets	(153		)	(594		)	(176		)	(700		)
Operating (loss) income	(10,273		)	2,894			(18,285		)	(3,220		)
Non-operating income expense:
Interest expense	(853		)	(433		)	(1,524		)	(10,625		)
(Loss) income before income tax	(11,126		)	2,461			(19,809		)	(13,845		)
Income tax expense	(154		)	(326		)	(331		)	(377		)
Net (loss) income	(11,280		)	2,135			(20,140		)	(14,222		)
Net loss attributable to predecessor	—			—			—			(1,546		)
Net (loss) income attributable to Quintana Energy Services Inc.	$	(11,280	)	$	2,135		$	(20,140	)	$	(12,676	)
Net (loss) income per common share:
Basic	$	(0.33	)	$	0.06		$	(0.60	)	$	(0.38	)
Diluted	$	(0.33	)	$	0.06		$	(0.60	)	$	(0.38	)
Weighted average common shares outstanding:
Basic	33,804			33,631			33,745			33,519
Diluted	33,804			35,227			33,745			33,519

The accompanying notes are an integral part of these condensed consolidated financial statements.

Quintana Energy Services Inc.

Condensed Consolidated Statement of Shareholders’ Equity

( in thousands of U.S dollars, units and shares)

(Unaudited)



	Common Unitholder Number of Units		Members' Equity			Common Shareholders Number of Shares Outstanding		Common Stock		Additional Paid in Capital			Treasury Stock			Accumulated Deficit			Total Shareholders’ Equity
Balance at December 31, 2017	417,441		$	212,630		—		$	—	$	—		$	—		$	(127,662	)	$	84,968
Effect of Reorganization Transactions	(417,441	)	(212,630		)	23,598		236		246,027			—			—			33,633
Issuance of common stock sold in initial public offering, net of offering costs	—		—			9,632		96		90,445			—			—			90,541
Net loss prior to Reorganization Transactions	—		—			—		—		—			—			(1,546		)	(1,546		)
Cost incurred for stock issuance	—		—			—		—		(4,307		)	—			—			(4,307		)
Equity-based compensation	—		—			401		4		9,882			—			—			9,886
Activity related to stock plan	—		—			—		—		—			(1,271		)	—			(1,271		)
Opening deferred tax adjustment	—		—			—		—		—			—			185			185
Net loss subsequent to Reorganization Transactions	—		—			—		—		—			—			(14,810		)	(14,810		)
Balance at March 31, 2018	—		$	—		33,631		$	336	$	342,047		$	(1,271	)	$	(143,833	)	$	197,279
Effect of Reorganization Transactions	—		—			—		2		(4		)	—			—			(2		)
Issuance of common stock sold in initial public offering, net of offering costs	—		—			—		—		1			—			—			1
Cost incurred for stock issuance	—		—			—		—		(969		)	—			—			(969		)
Equity-based compensation	—		—			—		2		2,938			—			—			2,940
Net income subsequent to Reorganization Transactions	—		—			—		—		—			—			2,134			2,134
Balance at June 30, 2018	—		$	—		33,631		$	340	$	344,013		$	(1,271	)	$	(141,699	)	$	201,383

Balance at December 31, 2018	—		$	—		33,541		$	344	$	349,080		$	(1,821	)	$	(145,783	)	$	201,820
Equity-based compensation	—		—			609		3		2,748			—			—			2,751
Tax withholding on stock vesting	—		—			(177	)	—		—			(954		)	—			(954		)
Stock buyback plan activity	—		—			(103	)	—		—			(486		)	—			(486		)
Net loss	—		—			—		—		—			—			(8,861		)	(8,861		)
Balance at March 31, 2019	—		$	—		33,870		$	347	$	351,828		$	(3,261	)	$	(154,644	)	$	194,270
Equity-based compensation	—		—			—		3		2,689			—			—			2,692
Stock buyback plan activity	—		—			(165	)	—		—			(522		)	—			(522		)
Net loss	—		—			—		—		—			—			(11,280		)	(11,280		)
Balance at June 30, 2019	—		$	—		33,705		$	350	$	354,517		$	(3,783	)	$	(165,924	)	$	185,160

The accompanying notes are an integral part of these condensed consolidated financial statements.

Quintana Energy Services Inc.

Condensed Consolidated Statements of Cash Flows

( in thousands of U.S. dollars)

(Unaudited)



	Six Months Ended
	June 30, 2019			June 30, 2018
Cash flows from operating activities:
Net loss	$	(20,140	)	$	(14,222	)
Adjustments to reconcile net loss to net cash used in operating activities
Depreciation and amortization	25,556			22,233
Gain on disposition of assets	(5,165		)	(3,068		)
Non-cash interest expense	174			855
Loss on debt extinguishment	—			8,594
Provision for doubtful accounts	300			460
Deferred income tax expense	67			—
Stock-based compensation	5,443			12,826
Changes in operating assets and liabilities:
Accounts receivable	16,566			(12,567		)
Unbilled receivables	5,635			(3,204		)
Inventories	(1,542		)	(5,051		)
Prepaid expenses and other current assets	2,743			1,331
Other noncurrent assets	11			(176		)
Accounts payable	(9,387		)	3,413
Accrued liabilities	(3,448		)	1,009
Other long-term liabilities	(106		)	(15		)
Net cash provided by operating activities	16,707			12,418
Cash flows from investing activities:
Purchases of property, plant and equipment	(21,521		)	(41,194		)
Proceeds from sale of property, plant and equipment	6,520			3,911
Net cash used in investing activities	(15,001		)	(37,283		)
Cash flows from financing activities:
Proceeds from revolving debt	7,500			33,000
Payments on revolving debt	(2,000		)	(81,071		)
Payments on term loans	—			(11,225		)
Payments on finance leases	(625		)	(182		)
Payments on financed payables	(1,839		)	—
Payment of deferred financing costs	—			(1,416		)
Prepayment premiums on early debt extinguishment	—			(1,346		)
Payments for treasury shares	(1,963		)	(1,271		)
Proceeds from new shares issuance, net of underwriting commissions	—			90,542
Costs incurred for stock issuance	—			(2,673		)
Net cash provided by financing activities	1,073			24,358
Net increase in cash and cash equivalents	2,779			(507		)
Cash and cash equivalents beginning of period	13,804			8,751
Cash and cash equivalents end of period	$	16,583		$	8,244



Supplemental cash flow information
Cash paid for interest	$	1,270	$	1,119
Income taxes paid	84		151
Supplemental non-cash investing and financing activities
Fixed asset purchases in accounts payable and accrued liabilities	$	1,513	$	570
Financed payables	426		—
Non-cash finance lease additions	8,696		—
Non-cash payment for property, plant and equipment	—		3,279
Debt conversion of Former Term Loan to equity	—		33,631
Issuance of common shares for members’ equity	—		212,630
Stock issuance cost included in accounts payable	—		501

The accompanying notes are an integral part of these condensed consolidated financial statements.

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QUINTANA ENERGY SERVICES INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

NOTE 1 - Organization and Nature of Operations and Basis of Presentation

Quintana Energy Services Inc. (either individually or together with its subsidiaries, as the context requires, the “Company,” “QES,” “we,” “us,” and “our”) is a Delaware corporation that was incorporated on April 13, 2017. Our accounting predecessor, Quintana Energy Services LP (“QES LP” and “Predecessor”), was formed as a Delaware partnership on November 3, 2014. In connection with our initial public offering (the “IPO”) which closed on February 13, 2018, the existing investors in QES LP and QES Holdco LLC contributed all of their direct and indirect equity interests to QES in exchange for shares of common stock in QES, and we became the holding company for the reorganized QES LP and its subsidiaries.

We are a diversified oilfield services provider of leading onshore oil and natural gas exploration and production (“E&P”) companies operating in both conventional and unconventional plays in all of the active major basins throughout the United States. The Company operates through four reporting segments which are Directional Drilling, Pressure Pumping, Pressure Control and Wireline.

Initial Public Offering

As of December 31, 2017, our Predecessor had approximately 417,441,074 common units outstanding and 227,885,579 warrants to purchase common units outstanding. Immediately prior to the IPO on February 13, 2018, the warrants were net settled for 223,394,762 common units, and immediately thereafter our Predecessor and affiliated entities were reorganized through mergers and related transactions and 20,235,193 shares of our common stock were issued to the holders of equity in our Predecessor at a ratio of 1 share of our common stock for 31.669363 common units of our Predecessor (with elimination of fractional shares) (the “Merger Transactions”). On February 13, 2018, immediately after the Merger Transactions, but prior to our IPO, our Predecessor’s Former Term Loan (as defined below) was extinguished and in partial consideration therefore 3,363,208 shares were issued to our Predecessor’s Former Term Loan lenders based on the price to the public of our IPO (representing 1 share of common stock for each $10.00 in Former Term Loan obligations converted) (together with the “Merger Transactions”, the “Reorganization Transactions”).

The gross proceeds of the IPO to the Company, at the public offering price of $10.00 per share, were $92.6 million , which resulted in net proceeds to the Company of approximately $87.0 million , after deducting $5.6 million of underwriting discounts and commissions associated with the shares sold by the Company, excluding approximately $5.3 million in offering expenses payable by the Company. Taking together the Reorganization Transactions and the issuance of 9,259,259 shares of our common stock to the public in our IPO, as of February 13, 2018, we had 32,857,660 shares outstanding immediately following our IPO. Subsequent to our IPO, we issued 139,921 shares in connection with the vesting of awards under our Predecessor’s 2015 LTIP Plan on February 22, 2018, and 260,529 shares of our common stock were issued on March 8, 2018 in consideration of vesting of awards under our Predecessor’s 2017 LTIP which we assumed. In connection with both awards, certain shares were withheld to satisfy tax obligations of the holder of the award, which shares are currently treasury shares totaling 136,585 shares of common stock. Also in connection with the consummation of the IPO, on March 9, 2018, the underwriters exercised their overallotment option to purchase an additional 372,824 shares of common stock of QES, which resulted in additional net proceeds of approximately $3.5 million (the “Option Exercise”), net of underwriter’s discounts and commission of $0.1 million . Upon the completion of the Reorganization Transactions, the IPO and the Option Exercise, QES had 33,630,934 shares of common stock outstanding.

The net proceeds received from the IPO and a $13.0 million drawdown on the New ABL Facility (described below) were used to fully repay the Company’s revolving credit facility balance of $81.1 million and repay $12.6 million of the Company’s $40.0 million , 10% Former Term Loan due 2020 , as described in “Note 4 - Long-Term Debt”. The remaining proceeds from the IPO were used for general corporate purposes.

Basis of Presentation and Principles of Consolidation

The accompanying interim unaudited condensed consolidated financial statements were prepared in accordance with accounting principles generally accepted in the United States of America (“U.S. GAAP”). These interim unaudited condensed consolidated financial accounts include all QES accounts and all of our subsidiaries. All inter-company transactions and account balances have been eliminated upon consolidation.

The accompanying interim unaudited condensed 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, 2018 , is derived from previously audited consolidated financial statements. In the opinion of management, all material adjustments, consisting of normal recurring adjustments, necessary for fair statement have been included.

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QUINTANA ENERGY SERVICES INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Certain reclassifications have been made to the prior year financial statements to conform to the current period financial statement presentation. These reclassification of costs between direct operating costs and general and administrative costs ("G&A") has no net impact to the condensed consolidated statements of income or to total segment reporting. Historically, and through December 31, 2018, certain direct operating costs related to business operations were classified and reported as G&A. The historical classification was consistent with the information used by our chief operating decision maker ("CODM") to assess performance of our segments and make resource allocation decisions, and the classification of such costs within the condensed consolidated statements of income was aligned with the segment presentation. Effective January 1, 2019, we changed the classification of certain of these costs in our segment reporting disclosures and within the condensed consolidated statements of income to reflect a change in the presentation of the information used by the Company’s CODM. For the three months ended June 30, 2019, we reclassified certain costs from G&A to direct operating costs, which decreased G&A by $8.0 million and increased direct operating costs by $8.0 million . For the six months ended June 30, 2018, G&A decreased by $17.6 million and direct operating cost increased by $17.6 million .

This reclassification of costs between direct operating costs and G&A has no net impact to the condensed consolidated statements of income or to total segment reporting. The change will better reflect the CODM's philosophy on assessing performance and allocating resources, as well as improve comparability to our peer group. This is a change in costs classification and has been reflected retrospectively for all periods presented.

These interim unaudited condensed 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 U.S. GAAP for complete financial statements. Therefore, these interim unaudited condensed consolidated financial statements should be read in conjunction with the Company’s audited consolidated financial statements and notes included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2018 (“ 2018 Annual Report”) filed with the SEC on March 8, 2019. 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.

There have been no material changes to the Company’s critical accounting policies or estimates from those disclosed in the 2018 Annual Report. The Company adopted certain accounting policies including the adoption of the Financial Accounting Standards Board (“FASB”) Accounting Standards Update (“ASU”) No. 2016-02, Leases, effective January 1, 2019. This ASU requires lessees to recognize an operating lease asset and a lease liability on the balance sheet.

Accounting Pronouncements

Recently Adopted Accounting Standard Update

Leases

In February 2016, the FASB issued ASU No. 2016-2, Leases ("Topic 842"), to provide guidance for the accounting for leasing transactions. The standard requires the lessee to recognize a lease liability along with a right-of-use ("ROU") asset for all leases with a term longer than one year. A lessee is permitted to make an accounting policy election by class of underlying asset to not recognize the lease liability and related ROU asset for leases with a term of one year or less. The provisions of this standard also apply to situations where the Company is the lessor. The requirements in this update are effective during interim and annual periods beginning after December 15, 2018. The Company adopted this new guidance effective January 1, 2019. ASC 842 requires a modified retrospective approach to each lease that existed at the date of initial application as well as leases entered into after that date. Under the transition method selected by QES, leases existing at, or entered into after, January 1, 2019 were required to be recognized and measured. Prior period amounts have not been adjusted and continue to be reflected in accordance with QES historical accounting. The Company has elected to report all leases at the beginning of the period of adoption and not restate its comparative periods. The adoption of ASU No. 2016-02 is discussed below and in Note 5 to our unaudited condensed consolidated financial statements herein.

The standard had a material impact on our unaudited condensed consolidated balance sheets, but did not have an impact on our unaudited condensed consolidated income statements. The most significant impact was the recognition of ROU assets and lease liabilities for operating leases, while our accounting for finance leases remained substantially unchanged.

The Company has elected to adopt the following practical expedients upon the transition date to Topic 842 on January 1, 2019:

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QUINTANA ENERGY SERVICES INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)


•	Transitional practical expedients package: An entity may elect to apply the listed practical expedients as a package to all the leases that commenced before the effective date. The practical expedients are:


◦	The entity need not reassess whether any expired or existing contracts are or contain leases;


◦	The entity need not reassess the lease classification for expired or existing contracts;


◦	The entity need not reassess initial direct costs for any existing leases.

•

Use of portfolio approach: An entity can apply this guidance to a portfolio of leases with similar characteristics if the entity reasonably expects that the application of the lease model to the portfolio would not differ materially from the application of the lease model to the individual leases in that portfolio. This approach can also be applied to other aspects of the lease guidance for which lessees/lessors need to make judgments and estimates, such as determining the discount rate and determining and reassessing the lease term.

Accounting Standard Update not yet adopted

In June 2018, the FASB issued ASU No. 2018-07, Compensation - Stock Compensation (Topic 718): Improvements to Nonemployee Share-Based Payment Accounting . This ASU is intended to simplify aspects of stock-based compensation issued to non-employees by making the guidance consistent with the accounting for employee stock-based compensation. The guidance is effective for the Company for the fiscal year beginning January 1, 2020. While the exact impact of this standard is not known, the guidance is not expected to have a material impact on the Company’s unaudited condensed consolidated financial statements, as non-employee stock compensation is nominal relative to the Company's total expenses as of June 30, 2019 .

In June 2016, the FASB issued ASU No. 2016-13, Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments. This ASU is intended to update the measurement of credit losses on financial instruments. This update improves financial reporting by requiring earlier recognition of credit losses on financing receivables and other financial assets in scope by using the Current Expected Credit Losses model (CECL). This guidance is effective for interim and annual periods beginning after December 15, 2019, with early adoption permitted. The Company is currently evaluating the impact this new guidance will have on its consolidated financial statements.

NOTE 2 - Inventories

Inventories consisted of the following ( in thousands of U.S. dollars ):



	June 30, 2019		December 31, 2018
Inventories:
Consumables and materials	$	6,945	$	7,566
Spare parts	18,060		15,898
Total Inventories	$	25,005	$	23,464

NOTE 3 - Accrued Liabilities

Accrued liabilities consist of the following ( in thousands of U.S. dollars ):



	June 30, 2019		December 31, 2018
Current accrued liabilities:
Accrued payables	$	11,460	$	12,943
Payroll and payroll taxes	9,452		7,051
Bonus	2,121		6,117
Workers compensation insurance premiums	1,631		1,532
Sales tax	2,210		2,599
Ad valorem tax	1,293		581
Health insurance claims	1,171		921
Other accrued liabilities	3,261		5,789
Total accrued liabilities	$	32,599	$	37,533

NOTE 4 - Long-Term Debt

Former Revolving Credit Facility

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QUINTANA ENERGY SERVICES INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

The Company had a revolving credit facility (“the Former Revolving Credit Facility”), which had a maximum borrowing facility of $110.0 million that was scheduled to mature on September 19, 2018. All obligations under the credit agreement for the Former Revolving Credit Facility were collateralized by substantially all of the assets of the Company. The Revolving Credit Facility’s credit agreement contained customary restrictive covenants that required the Company not to exceed or fall below two key ratios, a maximum loan to value ratio of 70% and a minimum liquidity of $7.5 million . In connection with the closing of the IPO on February 13, 2018, we fully repaid and terminated the Former Revolving Credit Facility. No early termination fees were incurred by the Company in connection with the termination of the Former Revolving Credit Facility. A loss on extinguishment of $0.3 million relating to unamortized deferred costs was recognized in interest expense during the first quarter of 2018.

Former Term Loan

The Company also had a four -year, $40.0 million term loan agreement (the "Former Term Loan") with a lending group, which included Geveran Investments Limited, Archer Holdco LLC and Robertson QES Investment LLC, an affiliate of Quintana Capital Group, L.P., that was scheduled to mature on December 19, 2020. The Former Term Loan agreement contained customary restrictive covenants that required the Company not to exceed or fall below two key ratios, a maximum loan to value ratio of 77% and a minimum liquidity of $6.8 million . The interest rate on the unpaid principal was 10.0% interest per annum and accrued on a daily basis. At the end of each quarter all accrued and unpaid interest was paid in kind by capitalizing and adding to the outstanding principal balance. In connection with the closing of the IPO on February 13, 2018, the Former Term Loan was settled in full by cash and common shares in the Company. In connection with the settlement of the Former Term Loan, a prepayment fee of 3% , or approximately $1.3 million was paid. The prepayment fee is recorded as a loss on extinguishment and included within interest expense. The Company also recognized within interest expense $5.4 million of unamortized discount expense and $1.7 million of unamortized deferred financing cost in interest expense during the first quarter of 2018.

New ABL Facility

In connection with the closing of the IPO on February 13, 2018, we entered into a new asset-based revolving credit agreement (the “New ABL Facility”) with each lender party thereto and Bank of America, N.A. as administrative agent and collateral agent. The New ABL Facility replaced the Former Revolving Credit Facility, which was terminated in conjunction with the effectiveness of the New ABL Facility. The New ABL Facility provides for a $100.0 million revolving credit facility subject to a borrowing base. Upon closing of the New ABL Facility, the borrowing capacity was $77.6 million and $13.0 million was immediately drawn. The loan interest rate on the $35.0 million borrowings outstanding at June 30, 2019 was 5.3% . The outstanding balance is recorded as long-term debt under the New ABL Facility. At June 30, 2019 , we had $16.6 million of cash and cash equivalents and $41.9 million net availability on the New ABL Facility, which resulted in a total liquidity position of $58.5 million .

The New ABL Facility contains various affirmative and negative covenants, including financial reporting requirements and limitations on indebtedness, liens, mergers, consolidations, liquidations and dissolutions, sales of assets, dividends and other restricted payments, investments (including acquisitions) and transactions with affiliates. Certain affirmative covenants, including certain reporting requirements and requirements to establish cash dominion accounts with the administrative agent, are triggered by failing to maintain availability under the New ABL Facility at or above specified thresholds or by the existence of an event of default under the New ABL Facility. The New ABL Facility provides for some exemptions to its negative covenants allowing the Company to make certain restricted payments and investments; subject to maintaining availability under the New ABL Facility at or above a specified threshold and the absence of a default.

The New ABL Facility contains a minimum fixed charge coverage ratio of 1.0 to 1.0 that is triggered when availability under the New ABL Facility falls below a specified threshold and is tested until availability exceeds a separate specified threshold for 30 consecutive days.

The New ABL Facility contains events of default customary for facilities of this nature, including, but not limited, to: (i) events of default resulting from the Company's failure or the failure of any credit party to comply with covenants (including the above-referenced financial covenant during periods in which the financial covenant is tested); (ii) the occurrence of a change of control; (iii) the institution of insolvency or similar proceedings against QES or any credit party; and (iv) the occurrence of a default under any other material indebtedness QES or any guarantor may have. Upon the occurrence and during the continuation of an event of default, subject to the terms and conditions of the New ABL Facility, the lenders will be able to declare any outstanding principal balance of our New ABL Facility, together with accrued and unpaid interest, to be immediately due and payable and exercise other remedies, including remedies against the collateral, as more particularly specified in the New ABL Facility. As of June 30, 2019 the Company was in compliance with all debt covenants.

NOTE 5 - Leases

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During the first quarter of 2019, the Company adopted Topic 842, effective January 1, 2019. This ASC requires lessees to recognize an operating lease asset and an operating lease liability on the balance sheet, with the exception of short-term leases.

Under the transition method selected by QES, leases existing at, or entered into after, January 1, 2019 are to be recognized and measured. Prior period amounts have not been adjusted and continue to be reflected in accordance with QES’s historical accounting. The adoption of this standard resulted in the recording of operating lease assets and operating lease liabilities of approximately of $29.1 million as of January 1, 2019, with no related impact on our condensed consolidated statement of shareholders' equity or condensed consolidated statement of operations. When available, we use the rate implicit in the lease to discount lease payments to present value; however, most of our leases do not provide a readily determinable implicit rate. Therefore, we must estimate our incremental borrowing rate to discount the lease payments based on information available at the lease commencement.

QES elected the package of practical expedients permitted under the transition guidance within the new standard which, among other things, allows companies to carry forward their historical lease classification. QES made an accounting policy election by class of underlying asset not to recognize the lease liability and related right-of-use asset for leases with a term of one year or less.

We have operating and finance leases for administrative offices, operations and manufacturing facilities, and certain equipment. Our leases have remaining lease terms of one year to eight years , some of which include options to extend the leases for up to five years , and some of which include options to terminate the leases within one year . Options to extend or terminate leases that are considered reasonably certain are included in our determination of the lease term.

The components of lease expense were as follows ( in thousands of U.S. dollars ):



	Three Months Ended June 30, 2019		Six Months Ended June 30, 2019
Operating lease cost:	$	3,720	$	6,794

Finance lease cost:
Amortization of ROU assets	493		585
Interest on lease liabilities	262		350
Total finance lease cost	755		935

Short-term lease cost:	$	307	$	486

Supplemental cash flow information related to leases was as follows ( in thousands of U.S. dollars ):



	Six Months Ended June 30, 2019
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows for operating leases	$	6,804
Operating cash flows for finance leases	294
Financing cash flows for finance leases	625

ROU assets obtained in exchange for lease obligations:
Operating leases	$	22,437
Finance leases	12,569

Supplemental balance sheet information related to leases was as follows ( in thousands of U.S. dollars, except lease term and discount rate ):

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	June 30, 2019
Operating Leases
Operating lease ROU assets	$	16,208

Other current liabilities	5,405
Long-term operating lease liabilities	10,844
Total operating lease liabilities	$	16,249

Finance Leases
Property and equipment, net	9,920

Other current liabilities	2,722
Long-term finance lease liabilities	9,222
Total finance lease liabilities	$	11,944

Weighted Average Remaining Lease Term
Operating leases (in years)	3.7
Finance leases (in years)	4.7

Weighted Average Discount Rate
Operating leases	8.9		%
Finance leases	8.6		%

Maturities of lease liabilities were as follows at June 30, 2019 ( in thousands of U.S. dollars ):



	Operating Leases			Finance Leases
Remainder of 2019	$	3,454		$	1,879
2020	5,857			3,719
2021	5,032			3,665
2022	2,888			2,949
2023	920			1,098
Thereafter	1,580			1,937
Total lease payments	19,731			15,247
Less: imputed interest	(3,482		)	(3,303		)
Total	$	16,249		$	11,944

At December 31, 2018, future minimum lease payments under the Company's finance leases for the five years ending December 31, 2019 through December 31, 2023 and thereafter are as follows: $0.7 million , $0.7 million , $0.6 million , $0.6 million , $0.6 million and $1.9 million , respectively.

At December 31, 2018, future minimum lease payments under the Company's operating leases for the five years ending December 31, 2019 through December 31, 2023 and thereafter are as follows: $11.0 million , $6.9 million , $6.3 million , $4.5 million , $1.1 million and $1.2 million , respectively.

NOTE 6 - Income Taxes

Quintana Energy Services LP was originally organized as a limited partnership and treated as a flow-through entity for federal and most state income tax purposes. As such, taxable income and any related tax credits were passed through to its members and included in their respective tax returns. As a result of the IPO and related Reorganization Transactions, Quintana Energy Services Inc. was formed as a corporation to hold all of the operational assets of Quintana Energy Services LP. Accordingly, in 2018, a

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provision for federal and state corporate income taxes was only made for the operations of Quintana Energy Services Inc. from February 8, 2018 through June 30, 2018 in the unaudited condensed consolidated financial statements.

As the Company does not operate internationally, income from continuing operations is sourced exclusively from the United States.

Income tax expense during interim periods is based on our estimated annual effective income tax rate plus any discrete items, which are recorded in the period in which they occur. Discrete items include, among others, such events as changes in estimates due to the finalization of tax returns, tax audit settlements, expiration of statutes of limitation, and increases or decreases in valuation allowances on deferred tax assets. Our effective tax rate was (1.4)% and 13.2% for the three months ended June 30, 2019 and 2018, respectively. Our effective tax rate was (1.7)% and (3.1)% for the six months ended June 30, 2019 and 2018, respectively.

The change in the effective tax rate for the three and six months ended June 30, 2019 as compared to the same period in 2018 was primarily due to Texas Margins Tax as applied against total gross receipts of the Company.

Tax positions are evaluated for recognition using a more-likely-than-not threshold, and those tax positions requiring recognition are measured as the largest amount of tax benefit that is greater than fifty percent likely of being realized upon ultimate settlement with a taxing authority that has full knowledge of all relevant information. The Company’s policy is to record interest and penalties relating to uncertain tax positions in income tax expense. At June 30, 2019, the Company did not have any accrued liability for uncertain tax positions and does not anticipate recognition of any significant liabilities for uncertain tax positions during the next 12 months.

The federal and state statutes of limitations have expired for all tax years prior to 2015 and we are not currently under audit by the IRS or any state jurisdiction.

NOTE 7 - Related Party Transactions

The Company utilizes some Quintana Capital Group, L.P. affiliate employees for certain accounting and risk management functions and incurs some tool rental and maintenance charges from Archer Well Company Inc. These amounts are reimbursed by the Company on a monthly basis.

At June 30, 2019 and 2018 , QES had the following transactions with related parties ( in thousands of U.S. dollars ):



	June 30, 2019		December 31, 2018
Accounts payable to affiliates of Quintana Capital Group, L.P.	$	—	$	—
Accounts payable to affiliates of Archer Well Company Inc.	$	35	$	40



	Three Months Ended June 30,
	2019		2018
Operating expenses from affiliates of Quintana Capital Group, L.P.	$	82	$	115
Operating expenses from affiliates of Archer Well Company Inc.	$	16	$	8



	Six Months Ended June 30,
	2019		2018
Operating expenses from affiliates of Quintana Capital Group, L.P.	$	254	$	222
Operating expenses from affiliates of Archer Well Company Inc.	$	19	$	11

NOTE 8 - 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 condensed consolidated financial position, results of operations, liquidity or capital resources. However, management does recognize that by the very nature of its business, material costs could be incurred in the future to maintain compliance. The amount of such future expenditures is not determinable due to several factors, including the unknown magnitude

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of possible regulation or liabilities, the unknown timing and extent of the corrective actions which may be required, the determination of the Company’s liability in proportion to other responsible parties and the extent to which such expenditures are recoverable from insurance or indemnification.

Litigation

The Company is a defendant or otherwise involved in a number of lawsuits in the ordinary course of business. Estimates of the range of liability related to pending litigation are made when the Company believes the amount and range of loss can be estimated and records its best estimate of a loss when the loss is considered probable. When a liability is probable, and there is a range of estimated loss with no best estimate in the range, the minimum estimated liability related to the lawsuits or claims is recorded. As additional information becomes available, the potential liability related to pending litigation and claims is assessed and the estimate is revised. Due to uncertainties related to the resolution of lawsuits and claims, the ultimate outcome may differ from estimates. The Company’s ultimate exposure with respect to pending lawsuits and claims is not expected to have a material adverse effect on our financial position, results of operations or cash flows.

An ongoing class action was filed during 2016 against one of the Company’s subsidiaries alleging violations of state based wage and hour laws and the Fair Labor Standards Act (“FLSA”) relating to non-payment of overtime pay. The Company believes its pay practices comply with the FLSA. The case is working its way through the various stages of the legal process, however, management believes the Company’s exposure is not material.

Other Commitments and Contingencies

The Company is not aware of any other matter that may have a material effect on its financial position or results of operations.

NOTE 9 - Segment Information

QES currently has four reportable segments: Directional Drilling, Pressure Pumping, Pressure Control and Wireline. These segments have been selected based on the Company’s CODM assessment of resource allocation and performance. The Company considers its Chief Executive Officer to be its CODM. The CODM evaluates the performance of our segments based on revenue and income measures, which include Adjusted EBITDA.

Directional Drilling

Our Directional Drilling segment is comprised of directional drilling services, downhole navigational and rental tools businesses and support services, including well planning and site supervision, which assists customers in the drilling and placement of complex directional and horizontal wellbores. This segment utilizes its fleet of in-house positive pulse measurement-while-drilling navigational tools, mud motors and ancillary downhole tools, as well as electromagnetic navigational systems. The demand for these services tends to be influenced primarily by customer drilling-related activity levels. We provide directional drilling and associated services to E&P companies in many of the most active areas of onshore oil and natural gas development in the United States, including the Permian Basin, Eagle Ford Shale, Mid-Continent region (including the SCOOP/STACK), Marcellus/Utica Shale and DJ/Powder River Basin.

Pressure Pumping

Our Pressure Pumping segment provides hydraulic fracturing stimulation services, cementing services and acidizing services. The majority of the revenues generated in this segment are derived from pressure pumping services focused on fracturing, cementing and acidizing services in the Permian Basin, Mid-Continent and Rocky Mountains regions. These pressure pumping and stimulation services are primarily used in the completion, production and maintenance of oil and gas wells. Customers for this segment include large public E&P operators as well as independent oil and gas producers.

Pressure Control

Our Pressure Control segment supplies a wide variety of equipment, services and expertise in support of completion and workover operations throughout the United States. Its capabilities include coiled tubing, snubbing, fluid pumping, nitrogen, well control and other pressure control related services. Our Pressure Control equipment is tailored to the unconventional resources market with the ability to operate under high pressures without having to delay or cease production during completion operations. We provide our pressure control services primarily in the Mid-Continent region (including the SCOOP/STACK), Eagle Ford Shale, Permian Basin, DJ/Powder River Basin, Haynesville Shale and Fayetteville Shale.

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Wireline

Our Wireline segment provides new well wireline conveyed tight-shale reservoir perforating services across many of the major U.S. shale basins and also offers a range of services such as cased-hole investigation and production logging services, conventional wireline, mechanical services and pipe recovery services. These services are offered in both new well completions and for remedial work. The majority of the revenues generated in our Wireline segment are derived from the Permian Basin, Eagle Ford Shale, Mid-Continent region (including the SCOOP/STACK), Haynesville Shale and East Texas Basin as well as in industrial and petrochemical facilities.

Segment Adjusted EBITDA

The Company views Adjusted EBITDA as an important indicator of segment performance. The Company defines Segment Adjusted EBITDA as net income (loss) plus income taxes, net interest expense, depreciation and amortization, impairment charges, net (gain) loss on disposition of assets - excluding (gain) loss of lost in hole assets, stock based compensation, transaction expenses, rebranding expenses, settlement expenses, severance expenses and equipment stand-up expense. The CODM uses Segment Adjusted EBITDA as the primary measure of segment operating performance.

The following table presents a reconciliation of Segment Adjusted EBITDA to net (loss) income ( in thousands of U.S. dollars ):



	Three Months Ended June 30,						Six Months Ended June 30,
	2019			2018			2019			2018
Segment Adjusted EBITDA:
Directional Drilling	$	5,854		$	5,242		$	15,334		$	7,822
Pressure Pumping	762			8,884			(2,742		)	18,774
Pressure Control	1,584			5,602			4,825			9,252
Wireline	384			788			2,447			3,351
Corporate and Other	(5,894		)	(7,061		)	(12,769		)	(20,886		)
Income tax expense	(154		)	(326		)	(331		)	(377		)
Interest expense	(853		)	(433		)	(1,524		)	(10,625		)
Depreciation and amortization	(13,116		)	(11,155		)	(25,556		)	(22,233		)
Gain on disposition of assets, net	153			594			176			700
Net loss	$	(11,280	)	$	2,135		$	(20,140	)	$	(14,222	)

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Financial information related to the Company’s total assets position as of June 30, 2019 and December 31, 2018 , by segment, is as follows ( in thousands of U.S. dollars ):



	June 30, 2019			December 31, 2018
Directional Drilling	$	116,346		$	105,942
Pressure Pumping	103,578			121,824
Pressure Control	73,036			70,401
Wireline	37,985			28,039
Total	$	330,945		$	326,206
Corporate & Other	4,923			7,344
Eliminations	(14,001		)	(9,001		)
Total assets	$	321,867		$	324,549

The following tables set forth certain financial information with respect to QES’ reportable segments ( in thousands of U.S. dollars):



	Three Months Ended June 30, 2019
	Directional Drilling		Pressure Pumping		Pressure Control		Wireline		Total
Revenues	$	54,380	$	24,038	$	27,646	$	19,563	$	125,627
Depreciation and amortization	3,071		5,823		3,166		1,056		13,116
Capital expenditures	$	5,343	$	547	$	2,363	$	630	$	8,883

	Three Months Ended June 30, 2018
	Directional Drilling		Pressure Pumping		Pressure Control		Wireline		Total
Revenues	$	43,605	$	56,702	$	31,965	$	20,264	$	152,536
Depreciation and amortization	2,547		5,467		2,168		973		11,155
Capital expenditures	$	4,646	$	18,620	$	5,269	$	244	$	28,779



	Six Months Ended June 30, 2019
	Directional Drilling		Pressure Pumping		Pressure Control		Wireline		Total
Revenues	$	116,335	$	52,670	$	56,421	$	41,866	$	267,292
Depreciation and amortization	6,038		11,301		6,096		2,121		25,556
Capital expenditures	$	8,734	$	3,836	$	7,411	$	1,540	$	21,521

	Six Months Ended June 30, 2018
	Directional Drilling		Pressure Pumping		Pressure Control		Wireline		Total
Revenues	$	81,207	$	110,102	$	59,926	$	42,569	$	293,804
Depreciation and amortization	5,153		11,004		4,081		1,995		22,233
Capital expenditures	$	7,355	$	23,831	$	9,649	$	359	$	41,194

NOTE 10 - Revenue

Performance Obligations and Transaction Price

Customers generally contract with us to provide an integrated service of personnel and equipment for directional drilling, pressure pumping, pressure control or wireline services. The Company is seen by the operator as the overseer of its services and is compensated to provide an entire suite of services. QES determined that each service contract contains a single performance obligation, which is each day’s service. In addition, each day’s service is within the scope of the series guidance as both criteria of series guidance are met per ASC 606: 1) each distinct increment of service (i.e. days available to supervise or number of stages determined at contract inception) that the Company agrees to transfer represents a performance obligation that meets the criteria for recognizing revenue over time, and 2) the Company would use the same method for measuring progress toward satisfaction

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(Unaudited)

of the performance obligation for each distinct increment of service in the series. Therefore, the Company has determined that each service contract contains one single performance obligation, which is the series of each distinct daily service rendered.

The transaction price for the Company’s service contracts is based on the amount of consideration the Company expects to receive for providing the services over the specified term and includes both fixed amounts and unconstrained variable amounts. In addition, the contract term may impact the determination and allocation of the transaction price and recognition of revenue. As the Company’s contracts do not stipulate substantive termination penalties, the contract is treated as day to day. Typically, the only fixed or known consideration at contract inception is initial mobilization and demobilization (where it is contractually guaranteed). In cases where the demobilization fee is not fixed, the Company estimates the variable consideration using the expected value method and includes this in the transaction price to the extent it is not constrained. Variable consideration is generally constrained if it is probable that a significant reversal in the amount of cumulative revenue recognized will occur when the uncertainty associated with the variable consideration is subsequently resolved. As the contracts are not enforceable, the contract price should not include any estimation for the day rate or stage rate charges.

Recognition of Revenue

Directional drilling, pressure pumping, pressure control and wireline services are consumed as the services are performed and generally enhances the customer or operators well site. Work performed on a well site does not create an asset with an alternative

use to the contractor since the well/asset being worked on is owned by the customer. Therefore, the Company’s measure of progress for our contracts are hours available to provide the services over the contracted duration. This unit of measure is representative of an output method as described in ASC 606.

The following chart details the types of fees found in a typical service contract and the related recognition method under ASC 606:



Fee type		Revenue Recognition
Day rate		Revenue is recognized based on the day rates earned as it relates to the level of service provided for each day throughout the contract.
Initial mobilization		Revenue is estimated at contract inception and included in the transaction price to be recognized ratably over contract term.
Demobilization		Unconstrained demobilization revenue is estimated at contract inception, included in the transaction price, and recognized ratably over the contract term.
Reimbursement		Recognized (gross of costs incurred) at the amount billed to the customer.

Disaggregation of Revenue

The Company discloses a reconciliation of the disaggregated revenue with the reported results in "Note 9 - Segment Information."

Future Performance Obligations and Financing Arrangements

As our contracts are day to day and short-term in nature, the Company determined that it does not have material future performance obligations or financing arrangements under its service contracts. Payments are typically due within 30 days after the services are rendered. The timing between the recognition of revenue and receipt of payment is not significant.

No contract assets or liabilities were recognized related to contracts with our customers.

NOTE 11 - Stock-Based Compensation

As of June 30, 2019 , the Company had three types of stock-based compensation under the Company's 2018 Long-Term Incentive Plan (i) restricted stock awards ("RSA") issued to directors (ii) restricted stock units (“RSU”) issued to executive officers and other key employees and (iii) performance stock units (“PSU”), which are RSUs with performance requirements, issued to executive officers and other senior management. Stock-based compensation issued prior to the Company’s IPO was subject to a dual vesting component, one of which was the time vesting component and the other was the consummation of a specified transaction, which included a public offering. As the public offering occurred on February 9, 2018, there was no stock-based compensation expense recognized in periods prior to the IPO. The stock-based compensation awards and units are classified as equity awards as they are settled in shares of QES common stock.

The following table summarizes stock-based compensation costs for the three months ended June 30, 2019 and 2018 (in thousands of U.S. dollars):

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(Unaudited)



	Three Months Ended June 30,				Six Months Ended June 30,
	2019		2018		2019		2018
Restricted stock awards	$	143	$	150	$	310	$	150
Restricted stock units	2,221		2,581		4,353		12,467
Performance stock units	328		209		781		209
Stock-based compensation expense	$	2,692	$	2,940	$	5,444	$	12,826


i.	Restricted Stock Awards

In March 2018, the Company's Compensation Committee of the Board of Directors approved the issuance of RSAs to the Company's non-executive directors. During the second quarter 2018, we granted 57,145 RSAs, which had a grant date fair value of $8.75 per share. The stock awards fully vested in February 2019.

The Company recognized these RSAs at fair value based on the closing price of the Company's common stock on the date of grant. The compensation expense associated with these RSAs will be amortized into income on a straight-line basis over the vesting period.

In January 2019, the Company's Compensation Committee of the Board of Directors approved the issuance of RSAs to the Company's non-executive directors. We granted 140,844 RSAs, which had a grant date fair value of $4.26 per share. The stock awards will fully vest in February 2020.

As of June 30, 2019 and 2018, the total unamortized compensation costs related to the non-executive RSAs was $0.4 million , which the Company expects to recognize over the remaining vesting period of 0.6 years .

ii. Restricted Stock Units

During the second quarter 2018, executive officers and key employees were granted a total of 476,042 RSUs, net of forfeitures, under the 2018 Long-Term Incentive Plan. These RSUs vest ratably over a three -year service condition with one-third vesting on each anniversary of the Company’s IPO provided that the employee remains employed by the Company at the applicable vesting date.

During the first quarter 2019, executive officers and key employees were granted a total of 897,967 RSUs, net of forfeitures, under the 2018 Long-Term Incentive Plan. These RSUs vest ratably over a three -year service condition with one-third vesting on each anniversary of the RSU's grant date provided that the employee remains employed by the Company at the applicable vesting date.

The Company recognized these RSUs at fair value based on the closing price of the Company's common stock on the date of grant. The compensation expense associated with these RSUs will be amortized into income on a straight-line basis over the vesting period.

As of June 30, 2019 and 2018 total unamortized compensation cost related to unvested restricted stock units were $ 16.1 million and $20.8 million , respectively, which the Company expects to recognize over the remaining weighted-average period of 2.10 years .

A summary of the status and changes during the three and six months ended June 30, 2019 of the Company’s shares of non-vested RSUs is as follows:

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(Unaudited)



	Number of Shares (in thousands)		Grant Date Fair Value per Share		Weighted Average Remaining Life (in years)
Outstanding at December 31, 2018:	1,551		$	15.74	2.36
Granted	898		4.26		2.87
Forfeited	(13	)	15.46		—
Vested	(509	)	14.77		—
Outstanding at March 31, 2019:	1,927		$	10.65	2.35
Granted	—		—		—
Forfeited	—		—		—
Vested	—		—		—
Outstanding at June 30, 2019	1,927		$	10.65	2.10

iii. Performance Stock Units

During the second quarter 2018, executive officers and senior management were granted a total of 425,083 PSUs under the 2018 Long-Term Incentive Plan. The PSUs were subject to both a performance and service requirement. The PSUs required the achievement of a certain performance as measured on December 31, 2018, based on (i) the Company’s performance with respect to relative total stockholder return and (ii) the Company’s performance with respect to absolute total stockholder return. Any PSUs that were not earned at the end of the performance period were forfeited. As a result of not fully achieving the performance measure, 297,558 PSUs were forfeited. The remaining 127,525 PSUs were earned and should the grantee satisfy the service requirement applicable to such earned performance share unit, vesting shall occur in equal installments on the first three anniversaries of the Company’s IPO.

During the first quarter 2019, executive officers and senior management were awarded a total of 646,966 PSUs under the 2018 Long-Term Incentive Plan. The PSUs are subject to both a performance and service requirement. Under current accounting guidance 323,483 of the awarded 646,966 PSU are accounted for as being granted. These 323,483 PSUs still require the achievement of a certain performance as measured on December 31, 2019, based on the Company’s performance with respect to relative total stockholder return and the other 323,483 PSUs, which were awarded but are not yet considered granted, are based on the performance of management and the Company during the period between January 1, 2019 and December 31, 2019 determined by the Board's compensation committee. Any PSUs that have not been earned at the end of a performance period will be forfeited. Should the grantee satisfy the service requirement applicable to such earned performance share unit, vesting shall occur in equal installments on the first three anniversaries of the award date.

The Company recognized the 323,483 PSUs deemed granted at their fair value determined using the Monte Carlo simulation model. The compensation expense associated with these PSUs will be amortized on a graded straight line basis over the vesting period. The PSUs that were awarded but not yet granted will be deemed granted on the date the Board's compensation committee determines how many PSUs have been earned. These additional earned PSUs will then be amortized on a straight line basis over the remaining vesting period, based on the grant date stock price.

As of June 30, 2019 and 2018, the total unamortized compensation cost related to unvested PSUs was $ 1.7 million and $2.1 million , respectively. The Company expects to recognize the expense over the remaining weighted-average period of 2.41 years .

A summary of the outstanding PSUs for the three and six months ended June 30, 2019 is as follows:

Table of Contents

QUINTANA ENERGY SERVICES INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)



	Number of Shares (in thousands)		Grant Date Fair Value per Share		Weighted Average Remaining Life (in years)
Outstanding at December 31, 2018:	128		$	5.49	2.11
Granted	323		3.98		2.87
Forfeited	(1	)	5.49		—
Vested	(43	)	5.49		—
Outstanding at March 31, 2019:	407		$	4.29	2.66
Granted	—		—		—
Forfeited	—		—		—
Vested	—		—		—
Outstanding at June 30, 2019	407		$	4.29	2.41

NOTE 12 - lncome (Loss) Per Share

Basic loss per share (“EPS”) is based on the weighted average number of common shares outstanding during the period. A reconciliation of the number of shares used for the basic EPS computation is as follows ( in thousands, except per share amounts ):



	Three Months Ended June 30,					Six Months Ended June 30,
	2019			2018		2019			2018
Numerator:
Net income (loss) attributed to common share holders	$	(11,280	)	$	2,135	$	(20,140	)	$	(12,676	)
Denominator:
Weighted average common shares outstanding - basic	33,804			33,631		33,745			33,519
Weighted average common shares outstanding - diluted	33,804			35,227		33,745			33,519
Net income (loss) per common share:
Basic	$	(0.33	)	$	0.06	$	(0.60	)	$	(0.38	)
Diluted	$	(0.33	)	$	0.06	$	(0.60	)	$	(0.38	)
Potentially dilutive securities excluded as anti-dilutive ¹	2,475			$	—	2,475			2,058

¹ The Company's potentially dilutive securities include outstanding RSAs, RSUs and PSUs.

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This Quarterly Report on Form 10-Q for the three and six months ended June 30, 2019 (this "Quarterly Report”) contains forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond our control. All statements, other than statements of historical fact included in this Quarterly Report, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this Quarterly Report, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on our current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements described under the heading “Risk Factors” included in this Quarterly Report and our Annual Report on Form 10-K for the fiscal year ended December 31, 2018. These forward-looking statements are based on management’s current beliefs, based on currently available information, as to the outcome and timing of future events.

Forward-looking statements may include statements about:



	•		our business strategy;



	•		our operating cash flows, the availability of capital and our liquidity;



	•		our future revenue, income and operating performance;



	•		uncertainty regarding our future operating results;



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



	•		our ability to maintain acceptable pricing for our services;



	•		our future capital expenditures;



	•		our ability to finance equipment, working capital and capital expenditures;



	•		competition and government regulations;



	•		our ability to obtain permits and governmental approvals;



	•		pending legal or environmental matters;



	•		loss or corruption of our information in a cyberattack on our computer systems;



	•		the supply and demand for oil and natural gas;



	•		the ability of our customers to obtain capital or financing needed for exploration and production (“E&P”) operations;



	•		business acquisitions;



	•		general economic conditions;



	•		credit markets;



	•		the occurrence of a significant event or adverse claim in excess of the insurance we maintain;



	•		seasonal and adverse weather conditions that can affect oil and natural gas operations;



	•		our ability to successfully develop our research and technology capabilities and implement technological developments and enhancements; and



	•		plans, objectives, expectations and intentions contained in this Quarterly Report that are not historical.

We caution you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control. These risks include, but are not limited to, decline in demand for our services, the cyclical nature and volatility of the oil and natural gas industry, a decline in, or substantial volatility of, crude oil and natural gas commodity prices, environmental risks, regulatory changes, the inability to comply with the financial and other covenants and metrics in our New ABL Facility (as defined below), cash flow and access to capital, the timing of development expenditures and the other risks described under “Risk Factors” set forth in our Annual Report on Form 10-K for the fiscal year ended December 31, 2018. For more information on our New ABL Facility, please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Our Credit Facility.”

Should one or more of the risks or uncertainties described in this Quarterly Report or any other risks or uncertainties of which we are currently unaware occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements.

All forward-looking statements, expressed or implied, included in this Quarterly Report are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.

Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this Quarterly Report.



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

The following discussion and analysis should be read in conjunction with the historical condensed consolidated financial statements and related notes included elsewhere in this Quarterly Report on Form 10-Q (“Quarterly Report”). This discussion contains forward-looking statements reflecting our current expectations and estimates and assumptions concerning events and financial trends that may affect our future operating results or financial position. Actual results and the timing of events may differ materially from those contained in these forward-looking statements due to a number of factors, including those discussed in the sections entitled “Risk Factors” and “Cautionary Note Regarding Forward-Looking Statements” appearing elsewhere in this Quarterly Report.

Overview

We are a diversified oilfield services provider of leading onshore oil and natural gas exploration and production (“E&P”) companies operating in conventional and unconventional plays in all of the active major basins throughout the United States. We classify the services we provide into four reportable segments: (1) Directional Drilling, (2) Pressure Pumping, (3) Pressure Control and (4) Wireline. Our Directional Drilling segment enables efficient drilling and guidance of the horizontal section of a wellbore using our technologically-advanced fleet of downhole motors and 117 measurement while drilling ("MWD") kits. Our Pressure Pumping segment includes hydraulic fracturing, cementing and acidizing services, and such services are supported by a high-quality pressure pumping fleet of approximately 267,475 hydraulic horsepower (“HHP”) as of June 30, 2019 . Our primary pressure pumping focus is on large hydraulic fracturing operations. Our Pressure Control segment provides various forms of well control, completions and workover applications through our 24 coiled tubing units, 9 of which are our 2.375 inch or larger ("Large Diameter"), 36 rig-assisted snubbing units and ancillary equipment. As of June 30, 2019 , our wireline services included 41 wireline units providing a full range of pump-down services in support of unconventional completions, and cased-hole wireline services enabling reservoir characterization.

The Company was incorporated on April 13, 2017. This Quarterly Report includes results for the first quarter of 2018 for our accounting Predecessor, Quintana Energy Services LP (“QES LP” or our “Predecessor”), which was formed as a Delaware partnership on November 3, 2014. In connection with our initial public offering (the “IPO”), we became the holding company for QES LP and its subsidiaries.

How We Generate Revenue and the Costs of Conducting Our Business

Our core businesses depend on our customers’ willingness to make expenditures to produce, develop and explore for oil and natural gas in the United States. Industry conditions are influenced by numerous factors, such as the supply of and demand for oil and natural gas, domestic and worldwide economic conditions, political instability in oil producing countries and merger and divestiture activity among oil and natural gas producers. The volatility of the oil and natural gas industry and the consequent impact on E&P activity could adversely impact the level of drilling, completion and workover activity by some of our customers. This volatility affects the demand for our services and the price of our services.

We derive a majority of our revenues from services supporting oil and natural gas operations. As oil and natural gas prices fluctuate significantly, demand for our services correspondingly change as our customers must balance expenditures for drilling and completion services against their available cash flows. Because our services are required to support drilling and completions activities, we are also subject to changes in spending by our customers as oil and natural gas prices fluctuate.

During the second quarter of 2019, the price of crude increased approximately 28.9% with WTI closing at $58.20 per barrel up from $45.15 per barrel on December 28, 2018. This increase partially offset the 38.6% decline of crude price in the fourth quarter of 2018. For the second quarter of 2018, WTI closed at $74.13 per barrel. The Baker Hughes Incorporated (“Baker Hughes”) lower 48 U.S. states land rig count has decreased from 1020 rigs on June 30, 2018 to 934 rigs as of June 30, 2019. The volatility and overall decline in crude oil prices had a moderately negative impact on our first and second quarter condensed consolidated results of operations, particularly those tied to activity in the U.S. shale play regions. While we started experiencing decreases in demand for our pressure pumping services in particular, demand for our directional drilling services improved compared to the same period last year. Due to the decrease in pressure pumping demand, we deactivated our third and fourth pressure pumping hydraulic fracturing fleets in January 2019 and March 2019, respectively. From the second quarter of 2018 through the second quarter of 2019, our Directional Drilling business segment increased the number of days we provided services to rigs and earned revenues during the period, including days that standby revenues were earned (“rig days”) by 29.4% , while day rates and market share improved compared to the same period last year. While utilization of our Wireline and Pressure Control assets remained consistent compared to the six months ended June 30, 2018, our Wireline segment experienced notable pricing improvements.

Directional Drilling : Our Directional Drilling segment provides the highly technical and essential services of guiding horizontal and directional drilling operations for E&P companies. We offer premium drilling services including directional drilling, horizontal drilling, under balanced drilling, MWD and rental tools. Our package also offers various technologies, including our positive pulse MWD navigational tool asset fleet, mud motors and ancillary downhole tools, as well as electromagnetic navigational systems. We also provide a suite of integrated and related services, including downhole rental tools. We generally provide directional drilling services on a day rate or hourly basis. We charge prevailing market prices for the services provided in this segment, and we may also charge fees for set up and mobilization of equipment depending on the job. Generally, these fees and other charges vary by location and depend on the equipment and personnel required for the job and the market conditions in the region in which the services are performed. In addition to fees that are charged during periods of active directional drilling, a stand-by fee is typically agreed upon in advance and charged on an hourly basis during periods when drilling must be temporarily ceased while other on-site activity is conducted at the direction of the operator or another service provider. We will also charge customers for the additional cost of oilfield downhole tools and rental equipment that is involuntarily damaged or lost-in-hole. Proceeds from customers for the cost of oilfield downhole tools and other equipment that is involuntarily damaged or lost-in-hole are reflected as product revenues.

Although we do not typically enter into long-term contracts for our services in this segment, we have long standing relationships with our customers in this segment and believe they will continue to utilize our services. As of June 30, 2019 , 88.1% of our directional drilling activity is tied to “follow-me rigs,” which involve non-contractual, generally recurring services as our Directional Drilling team members follow a drilling rig from well-to-well or pad-to-pad for multiple wells or pads, and in some cases, multiple years. With increasing use of pad drilling and reactivation of rigs during 2018, we have increased the number of “follow me rigs” from approximately 53 in June of 2018 to 67 as of June 30, 2019 .

Our Directional Drilling segment accounted for approximately 43.3% and 28.6% of our revenues for the three months ended June 30, 2019 and 2018, respectively.

Pressure Pumping : Our Pressure Pumping segment provides hydraulic fracturing services including hydraulic fracturing stimulation, cementing and acidizing services. The majority of the revenues generated in this segment are derived from hydraulic fracturing services in the Permian Basin, Mid-Continent and Rocky Mountain regions. During the second quarter, the utilization for Pressure Pumping's two active hydraulic fracturing fleets was 92.8% , consistent with the same period in 2018.

Our hydraulic fracturing services are based upon a purchase order, contract or on a spot market basis. Services are bid on a stage rate or job basis (for fracturing services) or job basis (for cementing and acidizing services), contracted or hourly basis. Jobs for these services are typically short-term in nature and range from a few hours to multiple days. Customers are charged for the services performed on location and mobilization of the equipment to the location. Additional revenue can be generated through product sales of some materials that are delivered as part of the service being performed.

Our Pressure Pumping segment accounted for approximately 19.1% and 37.2% of our revenues for the three months ended June 30, 2019 and 2018, respectively.

Pressure Control: Our Pressure Control segment provides a wide scope of Pressure Control services, including coiled tubing, rig assisted snubbing, nitrogen, fluid pumping and well control services.

Our coiled tubing units are used in the provision of unconventional completion services or in support of well-servicing and workover applications. Our rig-assisted snubbing units are used in conjunction with a workover rig to insert or remove downhole tools or in support of other well services while maintaining pressure in the well, or in support of unconventional completions. Our nitrogen pumping units provide a non-combustible environment downhole and are used in support of other pressure control or well-servicing applications.

Jobs for our Pressure Control services are typically short-term in nature and range from a few hours to multiple days. Customers are charged for the services performed and any related materials (such as friction reducers and nitrogen materials) used during the course of the services, which are reported as product sales. We may also charge for the mobilization and set-up of equipment, the personnel on the job, any additional equipment used on the job and other miscellaneous materials.

Our Pressure Control segment accounted for approximately 22.0% and 21.0% of our revenues for the three months ended June 30, 2019 and 2018, respectively.

Wireline: Our Wireline segment principally works in connection with hydraulic fracturing services in the form of pump-down services for setting plugs between hydraulic fracturing stages, as well as with the deployment of perforation equipment in connection with “plug-and-perf” operations. We offer a full range of other pump-down and cased-hole wireline services. We also provide cased-hole production logging services, injection profiling, stimulation performance evaluation and water break-through identification via this segment. In addition, we provide industrial logging services for cavern, storage and injection wells.

We provide our wireline services on a spot market basis or subject to a negotiated pricing agreement. Jobs for these services are typically short-term in nature, lasting anywhere from a few hours to a few weeks. We typically charge the customer for these services on a per job basis at agreed-upon spot market rates.

Our Wireline segment accounted for approximately 15.6% and 13.3% of our revenues for the three months ended June 30, 2019 and 2018, respectively.

How We Evaluate Our Operations

Our management team utilizes a number of measures to evaluate the results of operations and efficiently allocate personnel, equipment and capital resources. We evaluate our segments primarily by asset utilization, revenue and Adjusted EBITDA.

For each of our business services segments, we measure our 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. We generally consider an asset to be working such days that it is at or in transit to a job location. Undue reliance should not be placed on utilization as an indicator of our financial or operating performance because depending on the type of service performed, requirements of the job as well as competitive factors, revenue and profitability can vary from job to job.

Adjusted EBITDA is a supplemental non-GAAP financial measure that is used by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies. Adjusted EBITDA is not a measure of net income or cash flows as determined by GAAP. We define Adjusted EBITDA as net income (loss) plus income taxes, net interest expense, depreciation and amortization, impairment charges, net (gain)/loss on disposition of assets, stock based compensation, transaction expenses, rebranding expenses, settlement expenses, severance expenses and equipment stand-up expense.

We believe Adjusted EBITDA is useful because it allows us to more effectively evaluate our operating performance and compare the results of our operations from period to period without regard to our financing methods or capital structure. We exclude the items listed above in arriving at Adjusted EBITDA because these amounts can vary substantially from company to company within our industry depending upon accounting methods, book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDA should not be considered as an alternative to, or more meaningful than, net income as determined in accordance with GAAP, or as an indicator of our operating performance or liquidity. Certain items excluded from Adjusted EBITDA are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of Adjusted EBITDA. Our computations of Adjusted EBITDA may not be comparable to other similarly titled measures of other companies. For a definition and description of Adjusted EBITDA and reconciliations of Adjusted EBITDA to net income, the most directly comparable financial measure calculated and presented in accordance with GAAP, please see “Adjusted EBITDA” below.

Items Affecting the Comparability of our Future Results of Operations to our Historical Results of Operations

The historical financial results of our Predecessor discussed below may not be comparable to our future financial results for the reasons described below.

•

QES is subject to U.S. federal and state income taxes as a corporation. Our Predecessor was treated as a flow-through entity for U.S. federal income tax purposes, and as such, was generally not subject to U.S. federal income tax at the entity level. Rather, the tax liability with respect to its taxable income was passed through to its partners. Accordingly, the financial data attributable to our Predecessor contains no expense for U.S. federal income taxes or income taxes in any state or locality (other than franchise tax in the State of Texas).


•	Our IPO served as a vesting event under the phantom unit awards granted under our Predecessor's 2015 and 2017 LTIP Plans. As a result, certain of our Predecessor's phantom unit awards fully vested and were settled in connection with the IPO and additional phantom unit awards will fully vest and be settled according to their vesting schedules.


•	As we continue to implement controls, processes and infrastructure applicable to companies with publicly traded equity securities, it is likely that we will incur additional selling, general and administrative (“G&A”), expenses relative to historical periods.

Recent Trends and Outlook

Demand for our services is predominantly influenced by the level of drilling and completion activity by E&P companies (“operators”), which is driven largely by the current and anticipated profitability of developing oil and natural gas reserves. WTI has increased from its low of $26.21 per Bbl in early 2016 to $58.20 per Bbl as of June 30, 2019 . Natural gas prices have increased from their lows of $1.64 per MMBtu in early 2016 to $2.42 per MMBtu as of June 30, 2019 . In trend with commodity prices, drilling and completion activity in the United States has increased, corresponding to improved demand for our services. We believe that supply and demand fundamentals for multi-year industry growth are still intact and will help extend the overall trend of increased commodity prices. In parallel, shale plays in the United States continue to evolve with both operators and service companies introducing significant efficiencies to drive cost from exploration and production work. We believe that improved commodity prices and continued improvement to cost of production are positive contributors for the anticipated profitability of operators and their demand for our services.

Market volatility remains present, however, and WTI dropped over 38% in the fourth quarter of 2018 only to surge back and recover most of these losses by the end of the second quarter of 2019. Despite WTI’s recovery, its fourth quarter decline and investor sentiment contributed to the moderation of 2019 budgets for operators as they appear to shift strategies from production growth to operating within cash flow and generating returns. While these developments may have caused near-term budget constraints for our customers, we believe this is a positive sign for the long-term prospects of our industry. If widely implemented, this strategic shift may moderate volatility in demand for our services, which over time could drive improved results.

We believe the mix of moderated 2019 budgets, a shifting strategy for operators to remain within cash flow, and the takeaway constraints in the Permian Basin reduced overall drilling and completions activity levels during the first half of 2019. We have seen the impact of the slowdown impact adjacent basins as hydraulic fracturing fleets migrated from the Permian Basin placing pressure on Mid-Continent pricing. We believe, however, that in the second half of 2019, there are several catalysts that could increase demand for our services from their current levels, including a constructive commodity price environment, improvements to takeaway capacity constraints in the Permian Basin and a material inventory of drilled but uncompleted wells. In May 2019 we started providing hydraulic fracturing services in the Permian Basin and currently service both the Permian Basin and the Mid-Continent Basin.

Our industry remains fragmented and there are ample opportunities for consolidation amongst service companies. For the remainder of 2019, we intend to continue to strengthen our operating divisions through a combination of organic growth and the pursuit of strategic acquisition opportunities.

Results of Operations

Three Months Ended June 30, 2019 Compared to Three Months Ended June 30, 2018

The following tables provide selected operating data for the periods indicated ( in thousands except Other Operational Data ).



	Three Months Ended
	June 30, 2019			June 30, 2018
	(Unaudited)
Revenues:	$	125,627		$	152,536
Costs and expenses:
Direct operating costs	109,075			124,592
General and administrative	13,862			14,489
Depreciation and amortization	13,116			11,155
Gain on disposition of assets	(153		)	(594		)
Operating (loss) income	(10,273		)	2,894
Non-operating income expense:
Interest expense	(853		)	(433		)
(Loss) income before income tax	(11,126		)	2,461
Income tax expense	(154		)	(326		)
Net (loss) income	$	(11,280	)	$	2,135



	Three Months Ended
	June 30, 2019		June 30, 2018
	(Unaudited)
Segment Adjusted EBITDA:
Directional Drilling	$	5,854	$	5,242
Pressure Pumping	762		8,884
Pressure Control	1,584		5,602
Wireline	384		788
Adjusted EBITDA ⁽¹⁾	$	5,875	$	17,918
Other Operational Data:
Directional drilling rig days ⁽²⁾	4,854		4,108
Average monthly directional rigs on revenue ⁽³⁾	71		61
Total hydraulic fracturing stages	810		947
Average hydraulic fracturing revenue per stage	$	27,545	$	56,000

⁽¹⁾

Adjusted EBITDA is a supplemental non-GAAP financial measure that is used by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies. For a definition and description of Adjusted EBITDA and reconciliations of Adjusted EBITDA to net income, the most directly comparable financial measure calculated and presented in accordance with GAAP, please read “Adjusted EBITDA” below.


⁽²⁾	Rig days represent the number of days we are providing services to rigs and are earning revenues during the period, including days that standby revenues are earned.


⁽³⁾	Rigs on revenue represents the average number of rigs earning revenue during a given time period, including days that standby revenues are earned.

Adjusted EBITDA

disposition of assets, stock based compensation, transaction expenses, rebranding expenses, settlement expenses, severance expenses and equipment stand-up expense.

We believe Adjusted EBITDA margin is useful because it allows us to more effectively evaluate our operating performance and compare the results of our operations from period to period without regard to our financing methods or capital structure. We exclude the items listed above in arriving at Adjusted EBITDA because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDA should not be considered as an alternative to, or more meaningful than, net income as determined in accordance with GAAP, or as an indicator of our operating performance or liquidity. Certain items excluded from Adjusted EBITDA are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of Adjusted EBITDA. Our computations of Adjusted EBITDA may not be comparable to other similarly titled measures of other companies.

The following table presents a reconciliation of the non-GAAP financial measures of Adjusted EBITDA to the most directly comparable GAAP financial measure for the three months ended June 30, 2019 and 2018 ( in thousands of U.S. dollars ):



	Three Months Ended
	June 30, 2019			June 30, 2018
Adjustments to reconcile Adjusted EBITDA to net loss:
Net (loss) income	$	(11,280	)	$	2,135
Income tax expense	154			326
Interest expense	853			433
Depreciation and amortization expense	13,116			11,155
Gain on disposition of assets, net	(153		)	(594		)
Non-cash stock based compensation	2,692			2,940
Rebranding expense ⁽¹⁾	—			53
Settlement expense ⁽²⁾	408			166
Severance expense ⁽³⁾	85			53
Equipment and stand-up expense ⁽⁴⁾	—			1,251
Adjusted EBITDA	$	5,875		$	17,918


⁽¹⁾	Relates to expenses incurred in connection with rebranding our segments.

⁽²⁾

For 2019, represents certain nonrecurring corporate professional fees related to contemplated mergers and acquisitions activities, legal fees for FLSA claims and other non-recurring settlement expenses that were recorded in general and administrative expenses. For 2018, represents legal fees for FLSA claims, facility closures and other non-recurring expenses that were recorded in general and administrative expenses.


⁽³⁾	Relates to severance expenses incurred in connection with programs implemented to reduce headcount in connection with industry trends and market conditions. During the three months ended June 30, 2019, $0.1 million was recorded in direct operating expenses and for the three months ended June 30, 2018, $0.1 million was recorded in general and administrative expenses.


⁽⁴⁾	Relates to equipment stand-up costs incurred in connection with the mobilization and redeployment of assets. For 2018, primarily represents costs relating to the deployment of our third pressure pumping fleet, of which, approximately $1.2 million was recorded in direct operating expenses and approximately $0.1 million was recorded in general and administrative expenses.

Revenue. The following table provides revenues by segment for the periods indicated (in thousands of U.S. dollars) :



	Three Months Ended
	June 30, 2019		June 30, 2018
Revenue:
Directional Drilling	$	54,380	$	43,605
Pressure Pumping	24,038		56,702
Pressure Control	27,646		31,965
Wireline	19,563		20,264
Total revenue	$	125,627	$	152,536

Revenue for the three months ended June 30, 2019 , decreased by $26.9 million, or 17.6% , to $125.6 million from $152.5 million for the three months ended June 30, 2018 . The change in revenue by segment was as follows:

Directional Drilling revenue increased by $10.8 million, or 24.8% , to $54.4 million for the three months ended June 30, 2019 , from $43.6 million for the three months ended June 30, 2018 . This increase was primarily attributable to a 17.5% increase in utilization, an 18.2% increase in rig days and a 7.4% increase in Directional Drilling's dayrate. Approximately 96.8% of our Directional Drilling segment revenue was derived from directional drilling and MWD activities for the three months ended June 30, 2019 compared to 95.0% for the three months ended June 30, 2018 . The change in utilization and pricing accounted for 69.0% and 31.0% of the Directional Drilling revenue increase, respectively.

Pressure Pumping revenue decreased by $32.7 million, or 57.7% , to $24.0 million for the three months ended June 30, 2019 , from $56.7 million for the three months ended June 30, 2018 . This decrease was primarily attributable to a decrease in demand for hydraulic fracturing in our areas of operation, which led to our stacking of two hydraulic fracturing fleets which occurred in January 2019 and late March 2019, as opposed to four hydraulic fracturing fleets that were in service during the three months ended June 30, 2018. This drove a corresponding 14.5% decrease in stages to 810 for the three months ended June 30, 2019 . Additionally, we experienced a 50.8% decrease in average revenue per stage to $27,545 for the three months ended June 30, 2019 , from $56,000 for the three months ended June 30, 2018 , due to pricing pressure driven by the current competitive dynamics in the market. Approximately 92.8% of our Pressure Pumping segment revenue was derived from hydraulic fracturing services for the three months ended June 30, 2019 , compared to 93.7% for the three months ended June 30, 2018 .

Pressure Control revenue decreased by $4.4 million, or 13.8% , to $27.6 million for the three months ended June 30, 2019 , from $32.0 million for the three months ended June 30, 2018 . This decrease was primarily attributable to pricing headwinds in the market which drove a 13.9% decrease in weighted average revenue per day to $19,735 for the three months ended June 30, 2019 , partially offset by an 8.5% increase in weighted average utilization to 34.1% . In addition, increased well control activities, more actively deployed Large Diameter coiled tubing units compared to the prior year, increased weighted average utilization and demand of our snubbing business continued to positively impact Pressure Control revenue during the three months ended June 30, 2019 .

Wireline revenue decreased by $0.7 million, or 3.5%, to $19.6 million for the three months ended June 30, 2019 , compared to $20.3 million for the three months ended June 30, 2018 . Wireline's revenue days decreased by 32.2% , which was offset by a 42.5% increase in revenue per day for the three months ended June 30, 2019 . Approximately 88.0% of our Wireline segment revenue was derived from unconventional services for the three months ended June 30, 2019 , compared to 80.2% for the three months ended June 30, 2018 .

Direct operating expenses . The following table provides our direct operating expenses by segment for the periods indicated (in thousands of U.S. dollars):



	Three Months Ended
	June 30, 2019		June 30, 2018
Direct operating expenses:
Directional Drilling	$	45,193	$	34,324
Pressure Pumping	21,682		47,582
Pressure Control	23,776		24,068
Wireline	18,424		18,618
Total direct operating expenses	$	109,075	$	124,592

Direct operating expenses for the three months ended June 30, 2019 decreased by $15.5 million, or 12.4% , to $109.1 million , from $124.6 million for the three months ended June 30, 2018 . The change in direct operating expense was attributable to our segments as follows:

Directional Drilling direct operating expenses increased by $10.9 million, or 31.8% , to $45.2 million for the three months ended June 30, 2019 , from $34.3 million for the three months ended June 30, 2018 . This increase was primarily attributable to a 17.5% increase in utilization and an 18.2% increase in rig days to 4,854 over the same period, which in turn resulted in increased direct operating expenses for personnel and equipment.

Pressure Pumping direct operating expenses decreased by $25.9 million, or 54.4% , to $21.7 million for the three months ended June 30, 2019 , from $47.6 million for the three months ended June 30, 2018 . This decrease was primarily attributable to decreased activity driven by a 14.5% decrease in hydraulic fracturing stages completed to 810 stages compared to 947 stages completed in the three months ended June 30, 2018 , which resulted in reduced direct operating expense associated with materials, equipment and personnel costs. Pressure Pumping deactivated two hydraulic fracturing fleets, one in January 2019 and one in

late March 2019, resulting in two active fleets at June 30, 2019 compared to four active fleets at June 30, 2018. This reduction in active spreads further contributed to lower direct operating expenses for the three months ended June 30, 2019.

Pressure Control direct operating expenses decreased by $0.3 million or 1.2% , to $23.8 million for the three months ended June 30, 2019 , from $24.1 million for the three months ended June 30, 2018 . This decrease was primarily attributable to lower costs associated with personnel, equipment and consumables for the three months ended June 30, 2019 .

Wireline direct operating expenses decreased by $0.2 million, or 1.1% , to $18.4 million for the three months ended June 30, 2019 , from $18.6 million for the three months ended June 30, 2018 . This decrease was primarily driven by decreased activity levels and headcount reductions driving lower costs associated with personnel, equipment and consumables.

General and administrative expenses ("G&A") . G&A expenses represent the costs associated with managing and supporting our operations. These expenses decreased by $0.6 million, or 4.1% , to $13.9 million for the three months ended June 30, 2019 , from $14.5 million for the three months ended June 30, 2018 . The decrease in general and administrative expenses was primarily driven by a lower non-cash stock based compensation expense of $2.7 million compared to $2.9 million as of the three months ended June 30, 2018 , and headcount reductions.

Depreciation and amortization . Depreciation and amortization increased by $1.9 million, or 17.0% , to $13.1 million for the three months ended June 30, 2019 , from $11.2 million for the three months ended June 30, 2018 . The increase in depreciation and amortization is primarily attributable to the additional deployed equipment currently in service compared to the three months ended June 30, 2018 .

Interest expense . Interest expense increased by $0.5 million, or approximately 125.0% , to $0.9 million for the three months ended June 30, 2019 , compared to $0.4 million for the three months ended June 30, 2018 . The increase in interest expense was primarily due to lower debt levels in the three months ended June 30, 2018 , compared to the current debt outstanding of $35.0 million as of June 30, 2019 .

Adjusted EBITDA . Adjusted EBITDA for three months ended June 30, 2019 decreased by $12.0 million , or 67.0% to $5.9 million from $17.9 million for the three months ended June 30, 2018 . The change in Adjusted EBITDA by segment was as follows:

Directional Drilling Adjusted EBITDA increased by $0.7 million, or 13.5% , to $5.9 million in the three months ended June 30, 2019 , compared to $5.2 million in the three months ended June 30, 2018 . The increase was primarily attributable to a 24.8% increase in revenue driven by increased market activity, partially offset by an associated 31.8% increase in direct operating costs.

Pressure Pumping Adjusted EBITDA of $0.8 million during the three months ended June 30, 2019 , decreased , compared to $8.9 million during the three months ended June 30, 2018 . This decrease was primarily attributable to a 57.7% decrease in revenue driven by market conditions which resulted in decreased hydraulic fracturing activity. Associated with softening market conditions, we stacked two fleets in January 2019 and March 2019 which contributed to the 54.4% overall decrease in direct operating expenses.

Pressure Control Adjusted EBITDA decreased by $4.0 million, or 71.4% to $1.6 million in the three months ended June 30, 2019 , compared to $5.6 million in the three months ended June 30, 2018 . The decrease was primarily attributable to a decrease in revenue during the second quarter driven by market conditions, a 3.8% decrease in total revenue days for the quarter, and a 1.2% decrease in direct operating expenses.

Wireline Adjusted EBITDA decreased by $0.4 million, or 50.0% to $0.4 million in the three months ended June 30, 2019 , compared to $0.8 million in the three months ended June 30, 2018 . The decrease was primarily attributable to a $0.4 million revenue decrease driven by a 32.2% decrease in revenue days, and an 8.2% increase in G&A expenses driven by a 22.3% increase in crewed utilization, partially offset by an increase in day rates, and a 1.1% decrease in direct operating expenses.

Six Months Ended June 30, 2019 Compared to Six Months Ended June 30, 2018

The following tables provide selected operating data for the periods indicated. (in thousands except Other Operational Data).



	Six Months Ended
	June 30, 2019			June 30, 2018
	(Unaudited)
Revenues:	$	267,292		$	293,804
Costs and expenses:
Direct operating costs	230,626			240,689
General and administrative	29,571			34,802
Depreciation and amortization	25,556			22,233
Gain on disposition of assets	(176		)	(700		)
Operating loss	(18,285		)	(3,220		)
Non-operating income expense:
Interest expense	(1,524		)	(10,625		)
Loss before income tax	(19,809		)	(13,845		)
Income tax expense	(331		)	(377		)
Net loss	$	(20,140	)	$	(14,222	)



	Six Months Ended
	June 30, 2019			June 30, 2018
	(Unaudited)
Segment Adjusted EBITDA:
Directional Drilling	$	15,334		$	7,822
Pressure Pumping	(2,742		)	18,774
Pressure Control	4,825			9,252
Wireline	2,447			3,351
Adjusted EBITDA ⁽¹⁾	$	13,429		$	33,400
Other Operational Data:
Directional drilling rig days ⁽²⁾	10,115			7,814
Average monthly directional rigs on revenue ⁽³⁾	75			59
Total hydraulic fracturing stages	1663			1908
Average hydraulic fracturing revenue per stage	$	29,575		$	54,281

⁽¹⁾

Adjusted EBITDA is a supplemental non-GAAP financial measure that is used by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies. For a definition and description of Adjusted EBITDA and reconciliations of Adjusted EBITDA to net income, the most directly comparable financial measure calculated and presented in accordance with GAAP, please read “Adjusted EBITDA” below.


⁽²⁾	Rig days represent the number of days we are providing services to rigs and are earning revenues during the period, including days that standby revenues are earned.


⁽³⁾	Rigs on revenue represents the average number of rigs earning revenue during a given time period, including days that standby revenues are earned.

Adjusted EBITDA

Adjusted EBITDA is not a measure of net income or cash flows as determined by GAAP. We define Adjusted EBITDA as net income (loss) plus income taxes, net interest expense, depreciation and amortization, impairment charges, net (gain) loss on disposition of assets, stock based compensation, transaction expenses, rebranding expenses, settlement expenses, severance expenses and equipment stand-up expense.

The following table presents a reconciliation of the non-GAAP financial measures of Adjusted EBITDA to the most directly comparable GAAP financial measure for the six months ended June 30, 2019 and 2018 ( in thousands of U.S. dollars ):



	Six Months Ended
	June 30, 2019			June 30, 2018
Adjustments to reconcile Adjusted EBITDA to net loss:
Net loss	$	(20,140	)	$	(14,222	)
Income tax expense	331			377
Interest expense	1,524			10,625
Depreciation and amortization expense	25,556			22,233
Gain on disposition of assets, net	(176		)	(700		)
Non-cash stock based compensation	5,443			12,826
Rebranding expense ⁽¹⁾	16			53
Settlement expense ⁽²⁾	791			389
Severance expense ⁽³⁾	84			53
Equipment and stand-up expense ⁽⁴⁾	—			1,766
Adjusted EBITDA	$	13,429		$	33,400


⁽¹⁾	Relates to expenses incurred in connection with rebranding our segments.

⁽²⁾

For 2019, represents represents certain nonrecurring corporate professional fees related to contemplated mergers and acquisitions activities, legal fees for FLSA claims and other non-recurring settlement expenses that were recorded in general and administrative expenses. For 2018, represents legal fees for FLSA claims, facility closures and other non-recurring expenses that were recorded in general and administrative expenses.


⁽³⁾	Relates to severance expenses incurred in connection with programs implemented to reduce headcount in connection with industry trends and market conditions. During the six months ended June 30, 2019, $0.1 million was recorded in direct operating expenses and for the six months ended June 30, 2018, $0.1 million was recorded in general and administrative expenses.

⁽⁴⁾

Relates to equipment stand-up costs incurred in connection with the mobilization and redeployment of assets. For 2018, primarily represents costs incurred in connection with the mobilization and redeployment of assets. During the six months ended June 30, 2018, approximately $1.6 million was recorded in direct operating expenses and approximately $0.1 million was recorded in general and administration expenses.

Revenue. The following table provides revenues by segment for the periods indicated (in thousands of U.S. dollars) :



	Six Months Ended
	June 30, 2019		June 30, 2018
Revenue:
Directional Drilling	$	116,335	$	81,207
Pressure Pumping	52,670		110,102
Pressure Control	56,421		59,926
Wireline	41,866		42,569
Total revenue	$	267,292	$	293,804

Revenue for the six months ended June 30, 2019 decreased by $26.5 million, or 9.0% , to $267.3 from $293.8 for the six months ended June 30, 2018 . The change in revenue by segment was as follows:

Directional Drilling revenue increased by 35.1 million, or 43.2% , to $116.3 million for the six months ended June 30, 2019 , from $81.2 million for the six months ended June 30, 2018 . This increase was primarily attributable to a 28.2% increase in utilization, a 29.4% increase in rig days and an increase in pricing. Approximately 96.9% of our Directional Drilling segment revenue was derived from directional drilling and MWD activities for the six months ended June 30, 2019 compared to 95.0% for the six months ended June 30, 2018 . The change in utilization and pricing accounted for 65.1% and 34.9% of the Directional Drilling revenue increase, respectively.

Pressure Pumping revenue decreased by $57.4 million , or 52.1% , to $52.7 million for the six months ended June 30, 2019 , from $ 110.1 million for the six months ended June 30, 2018 . This decrease was primarily attributable to a decrease in demand for hydraulic fracturing services in our areas of operation, which led to our stacking of two hydraulic fracturing fleets that occurred in January 2019 and late March 2019, as opposed to our four hydraulic fracturing fleets that were in service during the six months ended June 30, 2018. This drove a corresponding 12.8% decrease in stages to $1,663 for the six months ended June 30, 2019 . Additionally, we experienced a 45.5% decrease in average revenue per stage to $29,575 for the six months ended June 30, 2019 , from $54,281 for the six months ended June 30, 2018 , due to pricing pressure driven by the current competitive dynamics in the market. Approximately 93.4% of our Pressure Pumping segment revenue was derived from hydraulic fracturing services for the six months ended June 30, 2019 , compared to 94.2% for the six months ended June 30, 2018 .

Pressure Control revenue decreased by $3.5 million , or 5.8% , to $56.4 million for the six months ended June 30, 2019 , from $59.9 million for the six months ended June 30, 2018 . This decrease was primarily attributable to pricing headwinds in the market, which drove a 2.2% decrease in weighted average revenue per day to $21,032 for the six months ended June 30, 2019 , partially offset by an 1.5% decrease in weighted average utilization to 31.8% . In addition, increased well control activities, more actively deployed Large Diameter coiled tubing units compared to the same period in 2018, increased weighted average utilization and increased demand of our snubbing business continued to positively impact Pressure Control revenue during the six months ended June 30, 2019 .

Wireline revenue decreased slightly by $0.7 million, or 1.6%, to $41.9 million for the six months ended June 30, 2019 , compared to $42.6 million for the six months ended June 30, 2018 . Revenue days decreased by 27.8% , which was offset by a 36.2% increase in revenue per day for the six months ended June 30, 2019 . We experienced a 4.2% increase in crewed utilization to 70.6% primarily associated with our conventional operations. Approximately 87.2% of our Wireline segment revenue was derived from unconventional services for the six months ended June 30, 2019 , compared to 81.6% for the six months ended June 30, 2018 .

Direct operating expenses . The following table provides our direct operating expenses by segment for the periods indicated (in thousands of U.S. dollars):



	Six Months Ended
	June 30, 2019		June 30, 2018
Direct operating expenses:
Directional Drilling	$	93,928	$	66,242
Pressure Pumping	51,992		90,222
Pressure Control	47,054		46,736
Wireline	37,652		37,489
Total direct operating expenses	$	230,626	$	240,689

Direct operating expenses for the six months ended June 30, 2019 decreased by $10.1 million , or 4.2% , to $230.6 million , from $240.7 million for the six months ended June 30, 2018 . The change in direct operating expense was attributable to our segments as follows:

Directional Drilling direct operating expenses increased by $27.7 million , or 41.8% , to $93.9 million for the six months ended June 30, 2019 , from $66.2 million for the six months ended June 30, 2018 . This increase was primarily attributable to a 28.2% increase in utilization and a 29.4% increase in rig days to 10,115 over the same period in 2018, which in turn resulted in increased direct operating expenses for personnel and equipment.

Pressure Pumping direct operating expenses decreased by $38.2 million , or 42.4% , to $52.0 million for the six months ended June 30, 2019 , from $90.2 million for the six months ended June 30, 2018 . This decrease was primarily attributable to decreased activity driven by a 12.8% decrease in hydraulic fracturing stages completed to 1,663 stages compared to 1,908 stages completed in the six months ended June 30, 2018 , which resulted in reduced direct operating expense associated with materials, equipment and personnel costs. Pressure Pumping deactivated two hydraulic fracturing fleets, one in January 2019 and one in

late March 2019, resulting in two active fleets at June 30, 2019 compared to four active fleets at June 30, 2018. This reduction in active fleets further contributed to lower direct operating expenses for the six months ended June 30, 2019 .

Pressure Control direct operating expenses increased by $0.4 million or 0.9% , to $47.1 million for the six months ended June 30, 2019 , from $46.7 million for the six months ended June 30, 2018 . Pressure Control direct operating expenses were consistent with the same period last year. The nominal increase was primarily attributable to higher direct labor costs and other cost increases involving insurance, rental and facilities expenses for the six months ended June 30, 2019 .

Wireline direct operating expenses decreased by $0.2 million , or 0.5% , to $37.7 million for the six months ended June 30, 2019 , from $37.5 million for the six months ended June 30, 2018 . This decrease was primarily due to a 27.8% decrease in revenue days and market driven headcount reductions.

General and administrative expenses ("G&A") . G&A expenses represent the costs associated with managing and supporting our operations. These expenses decreased by $5.2 million , or 14.9% , to $29.6 million for the six months ended June 30, 2019 , from $34.8 million for the six months ended June 30, 2018 . The decrease in G&A expenses was primarily driven by a lower non-cash stock based compensation expense of $5.4 million, compared to $12.8 million as of the six months ended June 30, 2018 , partially offset by an increase in G&A expenses for the additional administrative expenses related to being a publicly traded company, outsourced professional services and other labor and lease costs.

Depreciation and amortization . Depreciation and amortization increased by $3.4 million , or 15.3% , to $25.6 million for the six months ended June 30, 2019 , from $22.2 million for the six months ended June 30, 2018 . The increase in depreciation and amortization is primarily attributable to the additional deployed equipment currently in service compared to six months ended June 30, 2018 .

Interest expense . Interest expense decreased by $9.1 million , or approximately 85.8% , to $1.5 million for the six months ended June 30, 2019 , compared to $10.6 million for the six months ended June 30, 2018 . The decrease in interest expense was primarily due to lower debt levels, which exceeded $110.0 million in the six months ended June 30, 2018 , compared to the current debt outstanding of $35.0 million as of June 30, 2019 .

Adjusted EBITDA . Adjusted EBITDA for six months ended June 30, 2019 decreased by $20.0 million , or 59.9% to $13.4 million from $33.4 million for the six months ended June 30, 2018 . The change in Adjusted EBITDA by segment was as follows:

Directional Drilling Adjusted EBITDA increased by $7.5 million , or 96.2% , to $15.3 million in the six months ended June 30, 2019 , compared to $7.8 million in the six months ended June 30, 2018 . The increase was primarily attributable to a 43.2% increase in revenue driven by increased market activity and a 29.4% increase in rig days, partially offset by an associated 41.8% increase in direct operating costs.

Pressure Pumping Adjusted EBITDA decreased by $21.5 million, or 114.4%, to $(2.7) million during the six months ended June 30, 2019 , compared to $18.8 million during the six months ended June 30, 2018 . This decrease was primarily attributable to a 52.1% decrease in revenue driven by market conditions which resulted in decreased hydraulic fracturing activity. Associated with the market conditions, we stacked two fleets in January 2019 and March 2019 which contributed to the 42.4% overall decrease in direct operating expenses.

Pressure Control Adjusted EBITDA decreased by $4.5 million , or 48.4% to $4.8 million in the six months ended June 30, 2019 , compared to $9.3 million in the six months ended June 30, 2018 . The decrease was primarily attributable to a decrease in revenue during the first half of 2019 driven by market conditions, a 3.8% decrease in total revenue days for the quarter, a 2.2% decrease in our weighted average revenue per day, and a 0.9% increase in direct operating expenses, which is offset by lower stock compensation expenses in the second quarter of 2019.

Wireline Adjusted EBITDA decreased by $1.0 million , or 29.4% to $2.4 million in the six months ended June 30, 2019 , compared to $3.4 million in the six months ended June 30, 2018 . The decrease was primarily attributable to a $0.8 million decline in revenue and a 27.8% decrease in revenue days, a 8.0% increase in G&A expenses driven by personnel, consumables and overhead costs resulting from increased utilization, partially offset by a 36.2% increase in dayrate.

Liquidity and Capital Resources

We require capital to fund ongoing operations, including maintenance expenditures on our existing fleet and equipment, organic growth initiatives, investments and acquisitions. Our primary sources of liquidity to date have been capital contributions from our equity holders and borrowings under the New ABL Facility (as defined below) and cash flows from operations. At June 30, 2019 , we had $16.6 million of cash and cash equivalents and $41.9 million net availability on the New ABL Facility, which resulted in a total liquidity position of $58.5 million .

Our directional drilling activity has continued to increase, wireline and pressure control activity has remained relatively flat and demand for our pressure pumping services has decreased given the increased volatility and overall decline in commodity prices since the third quarter of 2018. Our cash flow from operations improved for the six months ended June 30, 2019 and we expect cash flow to continue to improve during the second half of 2019. However, there is no certainty that cash flow will continue to improve or that we will have positive operating cash flow for a sustained period of time. Our operating cash flow is sensitive to many variables, the most significant of which are utilization and profitability, the timing of billing and customer collections, payments to our vendors, repair and maintenance costs and personnel, any of which may affect our cash available.

Our primary use of capital resources has been for funding working capital and investing in property and equipment used to provide our services. Our primary uses of cash are maintenance and growth capital expenditures, including acquisitions and investments in property and equipment. We regularly monitor potential capital sources, including equity and debt financings, in an effort to meet our planned capital expenditure and liquidity requirements. Our future success will be highly dependent on our ability to access outside sources of capital.

The following table sets forth our cash flows for the periods indicated (in thousands of U.S. dollars) presented below:



	Six Months Ended
	June 30, 2019			June 30, 2018
Net cash provided by operating activities	$	16,707		$	12,418
Net cash used in investing activities	(15,001		)	(37,283		)
Net cash provided by financing activities	1,073			24,358
Net change in cash	2,779			(507		)
Cash balance end of period	$	16,583		$	8,244

Net cash provided by operating activities

Net cash provided by operating activities was $16.7 million for the six months ended June 30, 2019 , compared to net cash provided by operating activities of $12.4 million for the six months ended June 30, 2018 . The increase in operating cash flows was primarily attributable to an increase in Directional Drilling rig days, higher average monthly Directional Drilling rigs on revenue and working capital in-flow due to the reduction in activity in the Pressure Pumping segment, compared to the higher Pressure Pumping utilization and pricing experienced during 2018 as a result of prevailing market conditions.

Net cash used in investing activities

Net cash used in investing activities was $15.0 million for the six months ended June 30, 2019 , compared to net cash used in investing activities of $37.3 million for the six months ended June 30, 2018 . The cash flow used in investing activities for the six months ended June 30, 2019 was used primarily for maintenance capital spending tied to our existing fleet and growth capital spending in Directional Drilling and Pressure Control. We purchased $21.5 million in equipment and received $6.5 million in exchange for selling assets for the six months ended June 30, 2019 , compared to $41.2 million of cash that was used to purchase equipment and the receipt of $3.9 million in exchange for selling assets during the six months ended June 30, 2018 .

Net cash provided by financing activities

Net cash provided by financing activities was $1.1 million for the six months ended June 30, 2019 , compared to net cash provided by financing activities of $24.4 million for the six months ended June 30, 2018 . During the first and second quarters of 2019, $1.0 million was paid for treasury shares in connection with our common stock repurchase program. During the first and second quarters of 2018, net cash provided by financing activities was primarily the result of net proceeds received from draws made on our New ABL Facility and the closing of our IPO.

Our Credit Facility

Former Revolving Credit Facility

We had a revolving credit facility which had a maximum borrowing facility of $110.0 million that was scheduled to mature on September 19, 2018. All obligations under the credit agreement for the Former Revolving Credit Facility were collateralized by substantially all of the assets of our Predecessor. The Former Revolving Credit Facility’s credit agreement contained customary restrictive covenants that required the Company not to exceed or fall below two key ratios, a maximum loan to value ratio of 70% and a minimum liquidity of $7.5 million . In connection with the closing of the IPO on February 13, 2018, we fully repaid and terminated the Former Revolving Credit Facility. No early termination fees were incurred by the Company in connection with the

termination of the Former Revolving Credit Facility. A loss on extinguishment of $0.3 million relating to unamortized deferred costs was recognized in interest expense.

Former Term Loan

We also had a four-year, $40.0 million term loan agreement with a lending group, which included Geveran, Archer Holdco LLC, an affiliate of Archer, and Robertson QES, that was scheduled to mature on December 19, 2020. The Former Term Loan contained customary restrictive covenants that required our Predecessor not to exceed or fall below two key ratios, a maximum loan to value ratio of 77% and a minimum liquidity of $6.75 million . The interest rate on the unpaid principal was 10.0% interest per annum and accrued on a daily basis. At the end of each quarter all accrued and unpaid interest was paid in kind by capitalizing and adding to the outstanding principal balance. In connection with the closing of the IPO on February 13, 2018, the Former Term Loan was settled in full by cash and common shares in the Company. In connection with the settlement of the Former Term Loan, a prepayment fee of 3% , or approximately $1.2 million was paid. The prepayment fee is recorded as a loss on extinguishment of debt and included within interest expense. The Company also recognized $5.4 million of unamortized discount expense and $1.7 million of unamortized deferred financing cost in connection with the termination of the Former Term Loan.

New ABL Facility

In connection with the closing of the IPO on February 13, 2018, we entered into a new semi-secured asset-based revolving credit agreement (the “New ABL Facility”) with each lender party thereto and Bank of America, N.A. as administrative agent and collateral agent. The New ABL Facility replaced the Former Revolving Credit Facility. The New ABL Facility provides for a $100.0 million revolving credit facility subject to a borrowing base. Upon closing of the New ABL Facility the borrowing capacity was $77.6 million and $13.0 million was immediately drawn. The loan interest rate on the $35.0 million borrowings outstanding at June 30, 2019 was 5.3% . The outstanding balance is recorded as long-term debt under the New ABL Facility. At June 30, 2019 , we had $16.6 million of cash and equivalents and $41.9 million net availability on the New ABL Facility, which resulted in a total liquidity position of $58.5 million .

The New ABL Facility contains various affirmative and negative covenants, including financial reporting requirements and limitations on indebtedness, liens, mergers, consolidations, liquidations and dissolutions, sales of assets, dividends and other restricted payments, investments (including acquisitions) and transactions with affiliates. Certain affirmative covenants, including certain reporting requirements and requirements to establish cash dominion accounts with the administrative agent, are triggered by failing to maintain availability under the New ABL Facility at or above specified thresholds or by the existence of an event of default under the New ABL Facility. The New ABL Facility provides for certain baskets and carve-outs from its negative covenants allowing the Company to make certain restricted payments and investments; subject to maintaining availability under the New ABL Facility at or above a specified threshold and the absence of a default thereunder.

The New ABL Facility contains events of default customary for facilities of this nature, including, but not limited, to: (i) events of default resulting from the Company’s failure or the failure of any credit party to comply with covenants (including the above-referenced financial covenant during periods in which the financial covenant is tested); (ii) the occurrence of a change of control; (iii) the institution of insolvency or similar proceedings against QES or any credit party; and (iv) the occurrence of a default under any other material indebtedness QES or any guarantor may have. Upon the occurrence and during the continuation of an event of default, subject to the terms and conditions of the New ABL Facility, the lenders will be able to declare any outstanding principal balance of our New ABL Facility, together with accrued and unpaid interest, to be immediately due and payable and exercise other remedies, including remedies against the collateral, as more particularly specified in the New ABL Facility. As of June 30, 2019 , we were in compliance with our debt covenants.

Capital Requirements and Sources of Liquidity

During the six months ended June 30, 2019 , our capital expenditures, including advance deposit on equipment, were approximately $8.7 million , $3.8 million , $7.4 million and $1.5 million in our Directional Drilling, Pressure Pumping, Pressure Control and Wireline segments, respectively, for aggregate capital expenditures of approximately $21.5 million , primarily for maintenance capital spending tied to our existing fleet and growth capital spending in our Directional Drilling and Pressure Control segments.

For the six months ended June 30, 2018 , our capital expenditures, excluding acquisitions, were approximately $7.4 million , $23.8 million , $9.6 million and $0.4 million in our Directional Drilling, Pressure Pumping, Pressure Control and Wireline segments, respectively, for aggregate net capital expenditures of approximately $41.2 million , primarily for the activation of our fourth hydraulic fracturing spread, conversion of two coiled tubing units during the second quarter of 2018 and capital expenditures on existing equipment.

We currently estimate that our annual capital expenditures for our existing assets, approved capacity additions and other projects during 2019 will range from $30.0 million to $35.0 million, leaving approximately $10.0 million to $15.0 million available for capital spending during the remainder of 2019. We expect to fund these expenditures through a combination of cash on hand, cash generated by our operations and borrowings under our New ABL Facility.

We believe that our operating cash flow and available borrowings under our New ABL Facility will be sufficient to fund our operations for the next twelve months. Our operating cash flow is sensitive to many variables, the most significant of which are pricing, utilization and profitability, the timing of billing and customer collections, the timing of payments to vendors, and maintenance and personnel costs, any of which may affect our cash available. Significant additional capital expenditures will be required to conduct our operations and there can be no assurance that operations and other capital resources will provide cash in sufficient amounts to maintain planned or future levels of capital expenditures and make expected distributions. Further, we do not have a specific acquisition budget for 2019 since the timing and size of acquisitions cannot be accurately forecasted. In the event we make one or more acquisitions and the amount of capital required is greater than the amount we have available for acquisitions at that time, we could be required to reduce the expected level of capital expenditures or distributions and/or seek additional capital. If we seek additional capital for that or other reasons, we may do so through borrowings under our New ABL Facility, joint venture partnerships, asset sales, offerings of debt and equity securities or other means. We cannot assure that this additional capital will be available on acceptable terms or at all. If we are unable to obtain funds we need, we may not be able to complete acquisitions that may be favorable to us or to finance the capital expenditures necessary to conduct our operations.

On August 8, 2018, our Board of Directors approved a $6.0 million stock repurchase program authorizing us to repurchase common stock in the open market. The timing and amount of stock repurchases will depend on market conditions and corporate, regulatory and other relevant considerations. Repurchases may be commenced or suspended at any time without notice. The program does not obligate QES to purchase any particular number of shares of common stock during any period or at all, and the program may be modified or suspended at any time, subject to the Company's insider trading policy and at the Company’s discretion. As of June 30, 2019 , the Company had repurchased 364,189 shares over the life of this program.

Contractual Obligations

As a smaller reporting company, we are not required to provide the disclosure required by Item 303(a)(5)(i) of Regulation S-K.

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, 2019 .

Critical Accounting Policies and Estimates

Other than the accounting impacts resulting from our adoption of Topic 842, which are discussed in Notes 1 and 5 to our condensed consolidated financial statements herein, as of June 30, 2019 , there were no significant changes in our critical accounting policies previously disclosed in Part II, Item 7 of our Annual Report on Form 10-K for the fiscal year ended December 31, 2018, filed with the SEC on March 7, 2019.

Recent Accounting Pronouncements

See "Note - 1 Nature of Operations, Basis of Presentation and Significant Accounting Policies" to our condensed consolidated financial statements for a discussion of recently issued accounting pronouncements.

Item 3. Quantitative and Qualitative Disclosures About Market Risk.

Pursuant to Item 305(e) of Regulation S-K, as a smaller reporting company, we are not required to provide the information required by this Item.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

We have established disclosure controls and procedures that are designed to ensure that the information required to be disclosed by the Company in the reports that it files or submits under the Securities Exchange Act of 1934, as amended (the "Exchange Act") is recorded, processed, summarized, and reported within the time periods specified in SEC rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to provide reasonable assurance that information required to be disclosed under the Exchange Act is accumulated and communicated to management, including its principal executive and financial officers (who are our Chief Executive Officer and Chief Financial Officer, respectively) as appropriate to allow timely decisions regarding required disclosure. In designing and evaluating our disclosure controls and procedures, management recognized that disclosure controls and procedures can provide only reasonable, not absolute, assurance that the objectives of the disclosure controls and procedures are met.

In connection with the preparation of this Quarterly Report on Form 10-Q for the quarter ended June 30, 2019 , an evaluation was performed under the supervision of and with the participation of management, including the Chief Executive Officer and Chief Financial Officer, of the effectiveness of the Company's disclosure controls and procedures. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that the Company's disclosure controls and procedures as defined in Rules 13a-15(c) and 15d-15(e) of the Exchange Act were effective as of June 30, 2019 to provide reasonable assurance that information required to be disclosed by the Company in reports that it files or submits under the Exchange Act is (i) recorded, processed, summarized and reported within the time periods specified in the SEC rules and forms and (ii) accumulated and communicated to the Company's management, including its Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.

Changes in Internal Control over Financial Reporting

Effective January 1, 2019, we adopted Topic 842. The adoption of this standard resulted in recording of operating lease assets and operating lease liabilities, with no related impact on our condensed consolidated statement of equity or condensed consolidated statement of operations for the three months ended June 30, 2019 . In connection with the adoption of the new standard, we implemented internal controls to ensure we adequately evaluated our contracts and properly assessed the impact of the new accounting standard. There were no other changes in our internal control over financial reporting that occurred during the three months ended June 30, 2019 , that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II

Item 1. Legal Proceedings

Due to the nature of our business, we are, from time to time, involved in other routine litigation or subject to disputes or claims related to our business activities, including workers’ compensation claims and employment related disputes. In the opinion of our management, none of the pending litigation, disputes or claims against us, if decided adversely, will have a material adverse effect on our financial condition, cash flows or results of operations.

Item 1A. Risk Factors

There have been no material changes to the risk factors disclosed in our 2018 Annual Report. For a detailed discussion of known material factors which could materially affect our business, financial condition or future results, refer to Part I, Item 1A “Risk Factors” in our 2018 Annual Report. 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

Under our $6.0 million common stock repurchase program approved by the Board on August 8, 2018, repurchases can be made from time to time in the open market based on market conditions and corporate, regulatory and other relevant considerations. The program may be modified or suspended at any time in the Company's discretion. As of June 30, 2019 , the Company had purchased 364,189 shares over the life of this program.

Table of Contents

QUINTANA ENERGY SERVICES INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)



2019	Total Number of Shares Purchased	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Maximum Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs (i n thousands )
January	38,352	$	4.35	38,352	$	5,296
February	26,200	$	5.19	26,200	$	5,160
March	38,889	$	4.84	38,889	$	4,972
April	45,734	$	4.74	45,734	$	4,755
May	24,188	$	4.46	24,188	$	4,647
June	94,519	$	2.26	94,519	$	4,433
Total	267,882			267,882

Item 3. Defaults Upon Senior Securities

Not applicable.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information.

Not applicable.

Item 6. Exhibits

Index to Exhibits



3.1	Amended and Restated Certificate of Incorporation of Quintana Energy Services Inc. (incorporated by reference to Exhibit 3.1 of Quintana Energy Services Inc.'s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2018, File No. 1-38383).
3.2	Amended and Restated Bylaws of Quintana Energy Services Inc. (incorporated by reference to Exhibit 3.3 of Quintana Energy Services Inc.'s Current Report on Form 8-K filed on February 14, 2018, File No. 1-38383).
10.1†	Amended and Restated Executive Employment Agreement, effective June 15, 2019, by and between the Company and D. Rogers Herndon (incorporated by reference to Exhibit 10.1 of the Company's Current Report on Form 8-K filed on June 24, 2019, File No. 1-38383).
10.2†	Amended and Restated Executive Employment Agreement, effective June 15, 2019, by and between the Company and Christopher J. Baker (incorporated by reference to Exhibit 10.2 of the Company's Current Report on Form 8-K filed on June 24, 2019, File No. 1-38383).
10.3†	Amended and Restated Executive Employment Agreement, effective June 15, 2019, by and between the Company and Keefer M. Lehner (incorporated by reference to Exhibit 10.3 of the Company's Current Report on Form 8-K filed on June 24, 2019, File No. 1-38383).
10.4†	Form of Amendment to Phantom Unit Agreement under the Quintana Energy Services Inc. Amended and Restated Long-Term Incentive Plan (incorporated by reference to Exhibit 10.4 of the Company's Current Report on Form 8-K filed on June 24, 2019, File No. 1-38383).
31.1*	Certification of Principal Executive Officer Pursuant to Rules 13a-14(a) and 15d-14(a) under the Securities Exchange Act of 1934, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*	Certification of Principal Financial Officer Pursuant to Rules 13a-14(a) and 15d-14(a) under the Securities Exchange Act of 1934, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1**	Certification of Principal Executive Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2**	Certification of Principal Executive Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.


*	Filed herewith.


**	Furnished herewith.


†	Management contract or compensatory plan or arrangement

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.



QUINTANA ENERGY SERVICES INC.

By:		/s/ Christopher J. Baker
		Christopher J. Baker
		President, Chief Executive Officer, and Director

Date: August 8, 2019

By:		/s/ Keefer M. Lehner
		Keefer M. Lehner
		Executive Vice President and Chief Financial Officer

Date: August 8, 2019

By:		/s/ Geoffrey C. Stanford
		Geoffrey C. Stanford
		Vice President and Chief Accounting Officer

Date: August 8, 2019

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