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 September 30, 2018
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from                      to                     
Commission File Number: 001-38383

 
 
 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)

 
 
 
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  ☒   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  ☒    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
 
☒ 
  
Smaller reporting company
 
 
 
 
 
 
 
 
 
 
 
  
Emerging growth company
 
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.  ☒
Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Act).    Yes  ☐    No  ☒
The number of shares of the registrant’s common stock, par value $0.01 per share, outstanding at November 1, 2018, was 33,630,934.



QUINTANA ENERGY SERVICES INC.
FORM 10-Q
TABLE OF CONTENTS
 
 
 
 
PART I - FINANACIAL INFORMATION
 
Item 1. Financial Statements
 
Condensed Consolidated Balance Sheets (Unaudited) as of September 30, 2018 and December 31, 2017
 
Condensed Consolidated Statements of Operations (Unaudited) for the three and nine months ended September 30, 2018 and 2017
 
Condensed Consolidated Statement of Shareholders Equity (Unaudited) for the nine months ended September 30, 2018
 
Condensed Consolidated Statements of Cash Flows (Unaudited) for the nine months ended September 30, 2018 and 2017
 
Notes to Condensed Consolidated Financial Statements (Unaudited)
 
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
 
Item 3. Quantitative and Qualitative Disclosures About Market Risk

 
Item 4. Controls and Procedures
PART II - OTHER INFORMATION
 
Item 1. Legal Proceedings
 
Item 1A. Risk Factors
 
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
 
Item 3. Defaults Upon Senior Securities
 
Item 4. Mine Safety Disclosures
 
Item 5. Other Information
 
Item 6. Exhibits
SIGNATURES
 



i


PART I
 
Item 1.
Financial Statements
Quintana Energy Services Inc.
Condensed Consolidated Balance Sheets
(in thousands, except per share and share amounts)
(Unaudited) 
 
 
September 30, 2018
 
December 31, 2017
ASSETS
Current assets
 
 
 
 
Cash and cash equivalents
 
$
22,070

 
$
8,751

Accounts receivable, net of allowance of $1,214 and $776
 
86,738

 
83,325

Unbilled receivables
 
9,480

 
9,645

Inventories (Note 3)
 
26,502

 
22,693

Prepaid expenses and other current assets
 
3,991

 
9,520

Total current assets
 
148,781

 
133,934

Property, plant and equipment, net
 
151,864

 
128,518

Intangible assets, net
 
9,472

 
10,832

Other assets
 
1,612

 
2,375

Total assets
 
$
311,729

 
$
275,659

LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities
 
 
 
 
Accounts payable
 
$
42,162

 
$
36,027

Accrued liabilities (Note 4)
 
33,724

 
33,825

Current portion of debt and capital lease obligations (Note 5)
 
413

 
79,443

Total current liabilities
 
76,299

 
149,295

Deferred income taxes
 
134

 
185

Long-term debt, net of deferred financing costs of $0 and $1,709 (Note 5)
 
30,000

 
37,199

Long-term capital lease obligations (Note 5)
 
3,560

 
3,829

Other long-term liabilities
 
136

 
183

Total liabilities
 
110,129

 
190,691

Commitments and contingencies
 

 

Shareholders’ and members’ equity
 
 
 
 
Members’ equity
 

 
212,630

Preferred shares, $0.01 par value, 10,000,000 authorized; none issued and outstanding
 

 

Common shares, $0.01 par value, 150,000,000 authorized; 33,765,486 issued; 33,630,934 outstanding
 
342

 

Additional paid-in-capital
 
346,580

 

Treasury stock, at cost, 134,552 common shares
 
(1,271
)
 

Accumulated deficit
 
(144,051
)
 
(127,662
)
Total shareholders’ and members’ equity
 
201,600

 
84,968

Total liabilities, shareholders’ and members’ equity
 
$
311,729

 
$
275,659

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

1


Quintana Energy Services Inc.
Condensed Consolidated Statements of Operations
(in thousands of dollars and shares, except per share amounts)
(Unaudited)
 
 
 
Three Months Ended
 
Nine Months Ended
 
 
September 30, 2018
 
September 30, 2017
 
September 30, 2018
 
September 30, 2017
Revenues:
 
$
150,897

 
$
113,274

 
$
444,701

 
$
307,170

Costs and expenses:
 
 
 
 
 
 
 
 
Direct operating costs
 
118,525

 
89,910

 
341,598

 
239,007

General and administrative
 
22,540

 
18,613

 
74,958

 
51,788

Depreciation and amortization
 
12,033

 
11,238

 
34,265

 
34,264

Gain on disposition of assets
 
(629
)
 
(310
)
 
(1,329
)
 
(2,300
)
Operating loss
 
(1,572
)
 
(6,177
)
 
(4,791
)
 
(15,589
)
Non-operating income (expense):
 
 
 
 
 
 
 
 
       Interest expense
 
(574
)
 
(2,901
)
 
(11,199
)
 
(8,290
)
       Other income
 

 
724

 

 
724

Loss before income tax
 
(2,146
)
 
(8,354
)
 
(15,990
)
 
(23,155
)
Income tax expense
 
(207
)
 
(84
)
 
(584
)
 
(69
)
Net loss
 
(2,353
)
 
(8,438
)
 
(16,574
)
 
(23,224
)
Net loss attributable to predecessor
 

 
(8,438
)
 
(1,546
)
 
(23,224
)
Net loss attributable to Quintana Energy Services Inc.
 
$
(2,353
)
 
$

 
$
(15,028
)
 
$

Net loss per common share:
 
 
 
 
 
 
 
 
Basic
 
$
(0.07
)
 
$

 
$
(0.45
)
 
$

Diluted
 
$
(0.07
)
 
$

 
$
(0.45
)
 
$

Weighted average common shares outstanding:
 
 
 
 
 
 
 
 
Basic
 
33,631

 

 
33,563

 

Diluted
 
33,631

 

 
33,563

 

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



2


Quintana Energy Services Inc.
Condensed Consolidated Statement of Shareholders’ Equity
(in thousands of dollars, units and shares)
(Unaudited)
 
 
 
Common
Unitholders
Number of
Units
 
Members’
Equity
 
Common
Shareholders
Number of
Shares
Outstanding
 
Common
Stock
 
Additional
Paid in
Capital
 
Treasury
Stock
 
Retained
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

 
238

 
246,023

 

 

 
33,631

Issuance of common stock sold in initial public offering, net of offering costs
 

 

 
9,632

 
96

 
90,446

 

 

 
90,542

Net loss prior to reorganization transactions
 

 

 

 

 

 

 
(1,546
)
 
(1,546
)
Cost incurred for stock issuance
 

 

 

 

 
(5,276
)
 

 

 
(5,276
)
Equity-based compensation
 

 

 
401

 
8

 
15,387

 

 

 
15,395

Activity related to stock plan
 

 

 

 

 

 
(1,271
)
 

 
(1,271
)
Opening deferred tax adjustment
 

 

 

 

 

 

 
185

 
185

Net loss subsequent to reorganization transactions
 

 

 

 

 

 

 
(15,028
)
 
(15,028
)
Balance at September 30, 2018
 

 
$

 
33,631

 
$
342

 
$
346,580

 
$
(1,271
)
 
$
(144,051
)
 
$
201,600


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



3


Quintana Energy Services Inc.
Condensed Consolidated Statements of Cash Flows
(in thousands of dollars)
(Unaudited) 
 

Nine Months Ended
 

September 30, 2018

September 30, 2017
Cash flows from operating activities:




Net loss

$
(16,574
)

$
(23,224
)
Adjustments to reconcile net loss to net cash used in operating activities




Depreciation and amortization

34,265


34,264

Gain on disposition of assets

(5,256
)

(8,812
)
Non-cash interest expense

944


4,522

Loss on debt extinguishment

8,594



Provision for doubtful accounts

573


(48
)
Deferred income tax expense

134


59

Stock-based compensation

15,395



Changes in operating assets and liabilities:




Accounts receivable

(3,986
)

(43,889
)
Unbilled receivables

164


818

Inventories

(3,809
)

(2,747
)
Prepaid expenses and other current assets

2,538


1,772

Other noncurrent assets

(9
)

(1,675
)
Accounts payable

4,158


4,549

Accrued liabilities

(101
)

16,013

Other long-term liabilities

(46
)

(44
)
Net cash provided by (used in) operating activities

36,984


(18,442
)
Cash flows from investing activities:




Purchases of property, plant and equipment

(53,112
)

(13,519
)
Proceeds from sale of property, plant and equipment

6,836


33,679

Net cash (used in) provided by investing activities

(46,276
)

20,160

Cash flows from financing activities:




Proceeds from revolving debt

37,000


6,485

Payments on revolving debt

(86,071
)

(17,414
)
Proceeds from term loans



5,000

Payments on term loans

(11,225
)


Payments on capital lease obligations

(280
)

(219
)
Payment of deferred financing costs

(1,564
)


Prepayment premiums on early debt extinguishment

(1,346
)


Payments for treasury shares

(1,271
)


Proceeds from new shares issuance, net of underwriting commission costs

90,542



Costs incurred for stock issuance

(3,174
)


Net cash provided by (used in) financing activities

22,611


(6,148
)
Net increase (decrease) in cash and cash equivalents

13,319


(4,430
)
Cash and cash equivalents beginning of period

8,751


12,219

Cash and cash equivalents end of period

$
22,070


$
7,789

 
 
 
 
 
Supplemental cash flow information




Cash paid for interest

1,608


3,502

Income taxes paid, net of refund

90


9

Supplemental non-cash investing and financing activities




Non-cash proceeds from sale of assets held for sale



3,990

Fixed asset purchases in accounts payable and accrued liabilities

1,989



Non-cash capital lease additions
 
53

 
70

Non-cash payment for property, plant and equipment

3,279



Debt conversion of term loan to equity

33,631



Issuance of common shares for members’ equity

212,630



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

4

Table of Contents
QUINTANA ENERGY SERVICES INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)



NOTE 1 – ORGANIZATION AND NATURE OF OPERATIONS
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 growth-oriented provider of diversified oilfield services to 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 business 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 134,552 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% term loan due 2020 (the “Former Term Loan”), as described in “Note 5 Long-Term Debt and Capital Lease Obligations.” The remaining proceeds from the IPO were used for general corporate purposes.
NOTE 2 – BASIS OF PRESENTATION AND PRINCIPLES OF CONSOLIDATION
The accompanying interim condensed consolidated financial statements were prepared in accordance with accounting principles generally accepted in the United States of America (“U.S. GAAP”). These interim condensed consolidated financial accounts include all QES accounts and all of our subsidiaries where we exercise control. All inter-company transactions and account balances have been eliminated upon consolidation.

The accompanying interim 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, 2017, is derived from previously audited consolidated financial statements. In the opinion of management, all material adjustments, consisting of normal recurring

5

Table of Contents
QUINTANA ENERGY SERVICES INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)


adjustments, necessary for fair statement have been included. Certain reclassifications have been made to the prior year financial statements to conform to the current period financial statement presentation.
These interim 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 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, 2017 (“2017 Annual Report”) filed with the SEC on March 30, 2018. 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 2017 Annual Report. The Company adopted certain accounting policies including the adoption of the Financial Accounting Standards Board (“FASB”) Accounting Standards Update (“ASU”) No. 2014-9, Revenue from Contracts with Customers (the “new revenue standard” or Accounting Standards Codification 606, (“ASC 606”)) on January 1, 2018. These revenue recognition policy updates are applied prospectively in our financial statements from January 1, 2018 forward. Reported financial information for the historical comparable period was not revised and continues to be reported under the accounting standards in effect during the historical periods as there is not a material impact related to adoption. For additional discussion of this adoption, see Note 10, “Revenue from Contracts with Customers.”
Recent Accounting Pronouncements
Adopted in 2018
In May 2014, the FASB issued ASU No. 2014-9, Revenue from Contracts with Customers (Topic 606), a comprehensive new revenue recognition standard that supersedes most existing industry-specific guidance. ASC 606 creates a framework by which an entity allocates the transaction price to separate performance obligations and recognizes revenue when each performance obligation is satisfied. Under the new standard, entities are required to use judgment and make estimates, including identifying performance obligations in a contract, estimating the amount of variable consideration to include in the transaction price, allocating the transaction price to each separate performance obligation and determining when an entity satisfies its performance obligations. The standard allows for either “full retrospective” adoption, meaning that the standard is applied to all of the periods presented with a cumulative catch-up in the earliest period presented, or “modified retrospective” adoption, meaning the standard is applied only to the most current period presented in the financial statements with a cumulative catch-up in the current period. In July and December 2016, the FASB issued various additional authoritative guidance for the new revenue recognition standard. The accounting standard is effective for reporting periods beginning after December 15, 2017 and did not have a material impact on the Company’s 2018 first quarter interim condensed consolidated financial position, results of operations and cash flows. The Company adopted ASC 606, effective January 1, 2018, utilizing the modified retrospective method of adoption. See Note 10, for more details on the adoption and impacts of implementing ASC 606.
In January 2017, FASB issued ASU No. 2017-1, Business Combinations (Topic 805): Clarifying the Definition of a Business. The amendments provide a more robust framework to use in determining when a set of assets and activities constitutes a business. The new standard was effective for the Company beginning on January 1, 2018. The standard did not have a material impact on the Company’s interim condensed consolidated financial position, results of operations and cash flows as it did not have any business combinations transactions.
In May 2017, the FASB issued ASU 2017-9, Compensation (Topic 718): Scope of Modification Accounting, which clarifies what constitutes a modification of a share-based payment award. The new standard was effective for the Company beginning on January 1, 2018. The standard did not have a material impact on the Company’s interim condensed consolidated financial position, results of operations and cash flows because there has been no modification to our equity-based payment awards.

In August 2016, the FASB issued ASU 2016-15, Classification of Certain Cash Receipts and Cash Payments providing new guidance on the classification of certain cash receipts and payments including debt extinguishment costs, debt prepayment costs, settlement of zero-coupon debt instruments, contingent consideration payments, proceeds from the settlement of insurance claims and life insurance policies and distributions received from equity method investees in the statement of cash flows. This update is required to be applied using the retrospective transition method to each period presented unless it is impracticable to be applied retrospectively. In such situation, this guidance is to be applied prospectively. The new standard was effective for the Company beginning on January 1, 2018, which did not impact 2017 results, but resulted in a $1.3 million prepayment premium cost being

6

Table of Contents
QUINTANA ENERGY SERVICES INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)


reported under financing activities relating to the debt extinguishment of the Company’s $40.0 million term loan at the closing of the IPO.
Accounting Standards 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 share-based compensation issued to non-employees by making the guidance consistent with the accounting for employee share-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 consolidated financial statements, as non-employee stock compensation is nominal relative to the Company's total expenses as of September 30, 2018.
In February 2016, the FASB issued ASU No. 2016-2, Leases. The new standard requires lessees to recognize a right of use asset and a lease liability for virtually all leases. The guidance is effective for the Company for the fiscal year beginning January 1, 2019. The Company's lease adoption committee is performing a detailed review of its lease portfolio by evaluating its population of leased assets and designing and implementing new processes and controls. While the exact impact of this standard remains unknown, the guidance is expected to have a material impact on the Company’s consolidated financial statements, due to the leased assets and corresponding lease liability that will be recognized, as the Company has material operating and real property lease arrangements for which it is the lessee.
NOTE 3 – Inventories
Inventories consisted of the following (in thousands of dollars):
 
 
September 30, 2018
 
December 31, 2017
Consumables and materials
 
$
8,343

 
$
7,085

Spare parts
 
18,159

 
15,608

     Inventories
 
$
26,502

 
$
22,693

NOTE 4 – Accrued Liabilities
Accrued liabilities consist of the following (in thousands of dollars):
 
 
September 30, 2018
 
December 31, 2017
Current accrued liabilities
 
 
 
 
Accrued payables
 
$
13,420

 
$
11,905

Payroll and payroll taxes
 
4,693

 
6,089

Bonus
 
5,540

 
6,019

Workers compensation insurance premiums
 
1,594

 
1,760

Sales tax
 
2,387

 
2,923

Ad valorem tax
 
1,795

 
728

Health insurance claims
 
1,056

 
913

Other accrued liabilities
 
3,239

 
3,488

     Total accrued liabilities
 
$
33,724

 
$
33,825















7

Table of Contents
QUINTANA ENERGY SERVICES INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)


NOTE 5 – Long-Term Debt and Capital Lease Obligations
Long-term debt consisted of the following (in thousands of dollars):
 
 
September 30, 2018
 
December 31, 2017
New ABL revolving credit facility due February 2023
 
$
30,000

 
$

Revolving credit facility
 

 
79,071

2017 term loan facility
 

 
44,328

Less: deferred financing costs
 

 
(1,709
)
Less: discount on term loan
 

 
(5,420
)
    Total debt obligations, net of discounts and deferred financing
 
30,000

 
116,270

Capital leases
 
3,973

 
4,200

Less: current portion of debt and capital lease obligation
 
(413
)
 
(79,443
)
    Long-term debt and capital lease obligations
 
$
33,560

 
$
41,027


Long-Term Debt
Former Revolving Credit Facility
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 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 $5.4 million of unamortized discount expense and $1.7 million of unamortized deferred financing cost, 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 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, 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 borrowings outstanding at September 30, 2018, was 4.8% and $30.0 million was outstanding under the New ABL Facility as of September 30, 2018. At September 30, 2018, we had $22.1 million of cash and cash equivalents and $47.7 million available to draw on the New ABL Facility, which resulted in a total liquidity position of $69.8 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

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QUINTANA ENERGY SERVICES INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)


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 Borrowers’ 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 the Borrowers or any credit party; and (iv) the occurrence of a default under any other material indebtedness the Borrowers 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 September 30, 2018 the Company was in compliance with debt covenants.
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 were included in their tax returns. Upon the IPO and related Reorganization Transactions, Quintana Energy Services Inc. was formed as a corporation to hold all of the operating companies of Quintana Energy Services LP, which was subsequently renamed Quintana Energy Services LLC. Accordingly, a provision for federal and state corporate income taxes has been made only for the operations of the Company from February 9, 2018 through September 30, 2018 in the accompanying unaudited condensed consolidated and combined financial statements.
Deferred income taxes are provided to reflect the future tax consequences or benefits of differences between the tax basis of assets and liabilities and their reported amounts in the financial statements using enacted tax rates. Because Quintana Energy Services Inc. is a taxable entity, the Company established a provision for deferred income taxes as of February 9, 2018. ASC 740, "Income Taxes", requires the Company to reduce its deferred tax assets by a valuation allowance if, based on the weight of the available evidence, it is more likely than not that all or a portion of a deferred tax asset will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences are deductible. As a result of the Company’s evaluation of both the positive and negative evidence, the Company determined it does not believe it is more likely than not that its deferred tax assets will be utilized in the foreseeable future and has recorded a valuation allowance. The valuation allowance as of September 30, 2018 fully offsets the impact of the initial benefit recorded related to the formation of Quintana Energy Services Inc. This initial deferred impact was recorded as an adjustment to equity due to a transaction between entities under common control.
ASC 740-270-25, Income Taxes - Interim Reporting, requires the Company to compute its interim tax provision by applying an estimated annual effective tax rate to ordinary income (or loss) and then computing the tax expense (or benefit) related to all other items individually.  The Company has incurred a year to date ordinary loss and anticipates to be in an ordinary loss position at the end of the fiscal year. As such, the interim period benefit shall be computed in accordance with ASC 740-270-30-5, in which the estimated annual effective tax rate shall be applied to the year to date ordinary income at the end of each interim period and any tax benefit as a result, shall be limited if determined the benefit will not be realized.
Total tax expense was $0.6 million resulting in a negative effective tax rate of 4.0% for the nine months ended September 30, 2018. The negative effective tax rate is primarily due to our full valuation allowance position and state tax expense which creates a deviation from the customary relationship between income tax (expense)/benefit and pre-tax income/(loss).
On December 22, 2017, the President of the United States signed into law the Tax Cuts and Jobs Act (the “Tax Reform Act”). The legislation significantly changed U.S. tax law by, among other things, lowering corporate income tax rates from a maximum of 35% to a 21% rate, effective January 1, 2018, changes to the utilization of net operating losses, abolition of alternate minimum tax and interest expense limitations. The Company has applied the new corporate tax rate and other applicable provisions to

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QUINTANA ENERGY SERVICES INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)


calculate its interim tax provision. Due to anticipated future guidance from Internal Revenue Service, and interpretation of the changes in tax law, the amounts recorded as a result of implementation of the Tax Reforms Act could be subject to change.
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 September 30, 2018, the Company did not have any accrued liability for uncertain tax positions.
NOTE 7 – Related Party Transactions
The Company utilizes some Quintana affiliate employees for certain corporate functions, such as accounting and risk management. These amounts are reimbursed by the Company on a monthly basis.
At September 30, 2018 and December 31, 2017, QES had the following transactions with related parties (in thousands of dollars):
 
 
September 30, 2018
 
December 31, 2017
Accounts payable to affiliates of Quintana
 
$
26

 
$
81

Accounts payable to affiliates of Archer Well Company Inc.
 
$
28

 
$
9

 
 
 
 
 
 
 
 
 
 
 
 
Three Months Ended
September 30,
 
 
2018
 
2017
Operating expenses from affiliates of Quintana
 
$
81

 
$
34

Operating expenses from affiliates of Archer Well Company Inc.
 
$
66

 
$

 
 
Nine Months Ended
September 30,
 
 
2018
 
2017
Operating expenses from affiliates of Quintana
 
$
303

 
$
263

Operating expenses from affiliates of Archer Well Company Inc.
 
$
77

 
$
52

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 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 near term to maintain compliance. The amount of such future expenditures is not determinable due to several factors, including the unknown magnitude of possible regulation or liabilities, the unknown timing and extent of the corrective actions which may be required, the determination of the Company’s liability in proportion to other responsible parties and the extent to which such expenditures are recoverable from insurance or indemnification.
Litigation
The Company is 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


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QUINTANA ENERGY SERVICES INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)


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.
A class action has been filed 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.
The Company is not aware of any other matters that may have a material effect on its financial position or results of operations.
NOTE 9 – Segment Information
QES currently has four reportable business segments: Directional Drilling, Pressure Pumping, Pressure Control and Wireline. These business segments have been selected based on the Company’s Chief Operating Decision Maker’s (the “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 business segments based on revenue and income measures, which include non-GAAP measures.
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 (“MWD”) navigational tools, mud motors and ancillary downhole tools, as well as electromagnetic (“EM”) 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 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 major 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, Marcellus/Utica Shale, DJ/Powder River Basin, Haynesville Shale, Fayetteville Shale and Williston Basins (including the Bakken Shale).
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 and tubing conveyed perforating services, 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.


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QUINTANA ENERGY SERVICES INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)



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, stock based compensation, transaction expenses, rebranding expenses, settlement expenses, severance expenses and equipment standup 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 (in thousands of dollars):
 

Three Months Ended
September 30,
 
Nine Months Ended
September 30,
 

2018

2017
 
2018
 
2017
Directional Drilling

$
6,452


$
3,423

 
$
14,273

 
$
11,965

Pressure Pumping

5,795


5,791

 
24,569

 
17,283

Pressure Control

4,421


835

 
13,673

 
2,434

Wireline

(738
)

(1,166
)
 
2,614

 
(3,329
)
Corporate and Other

(6,098
)

(4,132
)
 
(26,984
)
 
(11,978
)
Income tax expense

(207
)

(84
)
 
(584
)
 
(69
)
Interest expense

(574
)

(2,901
)
 
(11,199
)
 
(8,290
)
Depreciation and amortization

(12,033
)

(11,238
)
 
(34,265
)
 
(34,264
)
Gain on disposition of assets, net

629


310

 
1,329

 
2,300

Other income
 

 
724

 

 
724

       Net loss

$
(2,353
)

$
(8,438
)
 
$
(16,574
)
 
$
(23,224
)

Financial information related to the Company’s total assets position as of September 30, 2018 and December 31, 2017, by segment, is as follow (in thousands of dollars):
 
 
September 30, 2018
 
December 31, 2017
Directional Drilling
 
$
97,886

 
$
82,789

Pressure Pumping
 
115,900

 
111,322

Pressure Control
 
64,053

 
52,884

Wireline
 
31,978

 
28,988

Total
 
$
309,817

 
$
275,983

Corporate & Other
 
6,912

 
7,695

Eliminations
 
(5,000
)
 
(8,019
)
       Total assets
 
$
311,729

 
$
275,659









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QUINTANA ENERGY SERVICES INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)


The following tables set forth certain financial information with respect to QES’ reportable business segments (in thousands of dollars):
 
 
Three Months Ended September 30, 2018
 
 
Directional
Drilling
 
Pressure
Pumping
 
Pressure
Control
 
Wireline
 
Total
Revenues
 
$
50,919

 
$
49,987

 
$
31,138

 
$
18,853

 
$
150,897

Depreciation and amortization
 
2,767

 
5,912

 
2,378

 
976

 
12,033

Capital expenditures
 
$
2,889

 
$
2,208

 
$
5,716

 
$
1,105

 
$
11,918

 
 
 
 
 
 
 
 
 
 
 
 
 
Three Months Ended September 30, 2017
 
 
Directional
Drilling
 
Pressure
Pumping
 
Pressure
Control
 
Wireline
 
Total
Revenues
 
$
38,704

 
$
39,446

 
$
22,533

 
$
12,591

 
$
113,274

Depreciation and amortization
 
2,945

 
5,599

 
1,638

 
1,056

 
11,238

Capital expenditures
 
$
2,308

 
$
406

 
$
1,943

 
$
173

 
$
4,830

 
 
Nine Months Ended September 30, 2018
 
 
Directional
Drilling
 
Pressure
Pumping
 
Pressure
Control
 
Wireline
 
Total
Revenues
 
$
132,127

 
$
160,089

 
$
91,063

 
$
61,422

 
$
444,701

Depreciation and amortization
 
7,920

 
16,915

 
6,459

 
2,971

 
34,265

Capital expenditures
 
$
10,244

 
$
26,039

 
$
15,365

 
$
1,464

 
$
53,112

 
 
 
 
 
 
 
 
 
 
 
 
 
Nine Months Ended September 30, 2017
 
 
Directional
Drilling
 
Pressure
Pumping
 
Pressure
Control
 
Wireline
 
Total
Revenues
 
$
106,952

 
$
103,636

 
$
63,392

 
$
33,190

 
$
307,170

Depreciation and amortization
 
9,208

 
17,140

 
4,698

 
3,218

 
34,264

Capital expenditures
 
$
6,438

 
$
1,974

 
$
4,831

 
$
276

 
$
13,519

NOTE 10 – Revenue from Contracts with Customers
In adopting ASC 606, the Company’s revenue recognition model largely aligns with its historical revenue recognition pattern. Immaterial differences may exist for contracts with initial mobilization and demobilization charges. We determined that the adoption of this standard did not have a material impact on our retained earnings at the beginning of the fiscal year 2018, our statement of operations or statement of cash flows.
The Company has also exercised the following practical expedients and accounting policy elections provided by ASC 606 for all its service contracts.
1)
QES occasionally pays commissions to its sales staff for successfully obtaining a contract. The commission payment is incremental costs of obtaining a contract and should be capitalized and amortized over the contract period. However, ASC 340-40-25-4 provides a practical expedient, which states that “an entity may recognize the incremental costs of obtaining a contract as an expense when incurred if the amortization period of the asset that the entity otherwise would have recognized is one year or less.” Management has elected to use this practical expedient as most of the Company’s service contracts are less than a month. Accordingly, the Company expenses the commission expense as incurred.
2)
In May 2016, the FASB issued ASU 2016-12 that allows an entity to make an accounting policy election to exclude from the transaction price certain types of taxes collected from a customer (i.e. present revenue net of these taxes), including sales, use, value-added and some excise taxes.

Typical Contractual Arrangements
The Company typically provides the services based upon a combination of a Master Service Agreement (“MSA”) or its General Terms & Conditions (T&Cs”) and a purchase order or other similar forms of work requests that primarily operate on a spot market basis for a defined work scope on a particular well or well pad. Services are provided based on a price book and bid on a day rate,

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QUINTANA ENERGY SERVICES INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)


stage rate or job basis. QES may also charge for the mobilization and set-up of equipment and for materials and consumables used in the services. Contracts generally are short-term in nature, ranging from a few hours to multiple weeks. Contracts typically do not stipulate substantive early termination penalties for either party. As such, the Company determined that its contracts are day to day, even though parties typically do not terminate the contract early during the normal course of business. In cases where the customer terminates the contract early, the Company has an enforceable right to payment for services performed to date. Under day rate contracts, we generally receive a contractual day rate for each day we are performing services. The contractual day rate may vary based on the status of the operations and generally includes a full operating rate and a standby rate. Other fees may be stipulated in the contract related to mobilization and setup of equipment and reimbursements for consumables and cost of tools and equipment, that are involuntarily damaged or lost-in-hole.
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 for its scope 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: 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 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 stage or day’s service.
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.

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QUINTANA ENERGY SERVICES INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)


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 September 30, 2018, the Company had three types of stock-based compensation under the Equity Incentive Plan Award 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 component, one of which was the consummation of a specified transaction, which included a public offering. As the public offering occurred on February 7, 2018, there was no stock-based compensation expense recognized in periods prior to the IPO.
The following table summarizes stock-based compensation costs for the three months and nine months ended September 30, 2018 (in thousands of dollars):
 
 
Three Months Ended
September 30,
 
Nine Months Ended
September 30,
 
 
2018
 
2017
 
2018
 
2017
Restricted stock awards
 
$
144

 
$

 
$
294

 
$

Restricted stock units
 
1,886

 

 
14,353

 

Performance stock units
 
539

 

 
748

 

Stock-based compensation expense
 
$
2,569

 
$

 
$
15,395

 
$

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 vest on the anniversary date of the Company’s IPO. RSAs were not granted in the third quarter of 2018.
    
For the three and nine months ended September 30, 2018, the Company recognized $0.1 million and $0.3 million of non-cash stock compensation expense into earnings, respectively, which is presented within selling, general and administration expense in the condensed consolidated statement of operations.

As of September 30, 2018, the total unamortized compensation costs related to the non-executive RSAs was $0.2 million, which the Company expects to recognize over the remaining vesting period of 0.4 years.

ii.Restricted Stock Units

During the second quarter 2018, executive officers and key employees were granted a total of 476,042 RSUs under the Equity Incentive Award 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. RSUs were not granted in the third quarter of 2018.

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.

Total RSU non-cash stock based compensation expense for the three and nine months ended September 30, 2018, was $1.9 million and $14.4 million, which is presented within selling, general and administrative expense in the condensed consolidated statements of operations.


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QUINTANA ENERGY SERVICES INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)


As of September 30, 2018 and 2017, total unamortized compensation cost related to unvested restricted stock units were $18.9 million and $27.7 million, respectively.

A summary of the status and changes during the nine months ended September 30, 2018 of the Company’s shares of non-vested RSUs is as follows:

 
 
Number of Shares
(in thousands)
 
Grant Date Fair
Value per Share
 
Weighted Average
Remaining Life
(in years)
Outstanding at December 31, 2017
 
1,627

 
17.73

 
3.46

Granted
 
476

 
8.92

 
2.36

Forfeited
 

 

 

Vested
 
(535
)
 

 

Outstanding at September 30, 2018
 
1,568

 

 
2.61


iii.Performance Stock Units

During the second quarter 2018, executive officers and senior management were granted a total of 425,083 PSUs under the Equity Incentive Award Plan. The PSUs are subject to both a performance and time vesting requirement. The PSUs require 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 have not been earned at the end of a performance period are 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 Company’s IPO.

The Company recognized these PSUs at the fair value determined using the Monte Carlo simulation model. The compensation expense associated with these PSUs will be amortized into income on a straight-line basis over the vesting period. For the three and nine months ended September 30, 2018, the Company recognized $0.5 million and $0.7 million of non-cash stock compensation expense into income, which is presented within selling, general and administrative expense in the condensed consolidated statements of operations. PSUs were not granted during the first quarter of 2018.

As of September 30, 2018, total unamortized compensation cost related to unvested PSUs was $1.6 million, which the Company expects to recognize over the remaining weighted-average period of 2.36 years.

A summary of the outstanding PSUs as of September 30, 2018 is as follows:

 
 
Number of Shares
(in thousands)
 
Grant Date Fair
Value per Share
 
Weighted Average
Remaining Life
(in years)
Outstanding at December 31, 2017
 

 

 

Granted
 
425

 
$
5.49

 
2.36

Forfeited
 

 

 

Vested
 

 

 

Outstanding at September 30, 2018
 
425

 
$
5.49

 
2.36

NOTE 12 – 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):

16

Table of Contents
QUINTANA ENERGY SERVICES INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)


 
Three Months Ended September 30, 2018
 
Nine Months Ended September 30, 2018
Numerator:
 
 
 
       Net loss attributed to common share holders
$
(2,353
)
 
$
(15,028
)
Denominator:

 
 
Weighted average common shares outstanding - basic
33,631

 
33,563

Weighted average common shares outstanding - diluted
33,631

 
33,563

Net loss per common share:

 
 
Basic
$
(0.07
)
 
$
(0.45
)
Diluted
$
(0.07
)
 
$
(0.45
)
The Company granted 2.1 million potentially dilutive RSAs, RSUs and PSUs as of the nine months ended September 30, 2018.

17


CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS
This Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2018 (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 most recent Annual Report on Form 10-K for the fiscal year ended December 31, 2017. 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;
leasehold or 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,

18


2017. For more information on our New ABL Facility, please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Our New ABL 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.

19


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 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 growth-oriented provider of diversified oilfield services to 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 business 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 115 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 267,000 hydraulic horsepower (“HHP”) as of September 30, 2018. Our primary pressure pumping focus is on large hydraulic fracturing jobs. Our Pressure Control segment provide various forms of well control, form completions and workover applications through our 23 coiled tubing units (8 of which are large diameter), 36 rig-assisted snubbing units and ancillary equipment. As of September 30, 2018, our wireline services included 44 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 and does not have historical financial operating results. This Quarterly Report includes the results of 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 gas in the United States. Industry conditions are influenced by numerous factors, such as the supply of and demand for oil and gas, domestic and worldwide economic conditions, political instability in oil producing countries and merger and divestiture activity among oil and gas producers. The volatility of the oil and 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 gas operations. As oil and gas prices fluctuate significantly, demand for our services changes correspondingly 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 gas prices increase or decrease.
While we started experiencing short-term decreases in our demand for services, at our Pressure Pumping business segment in particular; demand for our services has continued to improve since May 2016 as oil and natural gas prices have increased from previous levels and as the Baker Hughes Incorporated (“Baker Hughes”) lower 48 U.S. states land rig count has increased from 375 rigs on May 27, 2016 to 1,054 rigs as of September 30, 2018. Although our industry experienced a significant downturn beginning in late 2014 and remained depressed for a prolonged period, which materially adversely affected our results in 2015 and 2016, the rebound in demand and increasing rig count beginning in May 2016 has improved both activity levels and pricing for our services. From the second quarter of 2016 through the third quarter of 2018, 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 248.9%, while day rates have improved from the lows we experienced during the second quarter of 2016. We reactivated our second and third pressure pumping hydraulic fracturing fleets in February and October 2017, and placed our fourth hydraulic fracturing fleet into service during June 2018. Utilization of our Pressure Control assets has also continued to improve since the second quarter of 2016.

20


Directional Drilling: Our Directional Drilling business 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 business 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 business segment, we have long standing relationships with our customers in this business segment and believe they will continue to utilize our services. As of the quarter ended September 30, 2018, 84.0% 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, through the first nine months of 2018 we have increased the number of “follow me rigs” from approximately 32 in January of 2016 to 69 as of the month ended September 30, 2018. We intend to continue to re-deploy additional MWD kits over the course of the fourth quarter and into 2019, as market conditions warrant.
Our Directional Drilling business segment accounted for approximately 33.7% and 34.2% of our revenues for the three months ended September 30, 2018 and 2017, respectively.
Pressure Pumping: Our Pressure Pumping business segment provides pressure pumping services including hydraulic fracturing stimulation, cementing and acidizing services. The majority of the revenues generated in this segment are derived from pressure pumping services in the Mid-Continent and Rocky Mountain regions.
Our Pressure Pumping 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 business segment accounted for approximately 33.1% and 34.8% of our revenues for the three months ended September 30, 2018 and 2017, respectively.
Pressure Control: Our Pressure Control business 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 business segment accounted for approximately 20.6% and 19.9% of our revenues for the three months ended September 30, 2018 and 2017, respectively.

21


Wireline: Our Wireline business 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 12.5% and 11.1% of our revenues for the three months ended September 30, 2018 and 2017, 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 business segments primarily by asset utilization, revenue and Adjusted EBITDA.
Adjusted EBITDA is not a measure of net income or cash flows as determined by U.S. generally accepted accounting principles (“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 standup expense.
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 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.
 
During the first nine months of 2017, we sold select pressure pumping and wireline assets for aggregate sale proceeds of $27.6 million. While we expect continued growth, expansions and strategic divestitures in the future, it is likely such growth, expansions and divestitures will be economically different from the acquisitions and divestitures discussed above, and such differences in economics will impact the comparability of our future results of operations to our historical results.
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).
As of September 30, 2018, we had actual outstanding indebtedness of $30.0 million.
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 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. We recognized $15.4 million of stock-based compensation expense during the first nine months of 2018. Expense associated with these phantom unit awards were recognized during the first nine months of 2018. See “Executive Compensation—QES LP Phantom Units” in our 2017 Annual Report on Form 10-K for additional detail on our phantom unit awards and our incentive plans.

22


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.
Our future results will depend on our ability to efficiently manage our combined operations and execute our business strategy.
Recent Trends and Outlook
Demand for our services is predominately influenced by the level of drilling and completion activity by E&P companies, which is driven largely by the current and anticipated profitability of developing oil and natural gas reserves. Crude oil prices have increased from their lows of $26.21 per barrel (“Bbl”) in early 2016 to $73.16 per Bbl as of September 30, 2018 (based on the West Texas Intermediate Spot Oil Price, or “WTI”), but remain 32% lower than a high of $107.26 per Bbl in June 2014. Natural gas prices have increased from their lows of $1.64 per million British Thermal Units (“MMBtu”) in early 2016 to $3.06 per MMBtu as of September 30, 2018, but remain 166.3% lower than a high of $8.15 per MMBtu in February 2014. Drilling and completion activity in the United States has increased significantly as commodity prices have generally increased, which we believe will correspond with increased demand for our services.
We expect E&P operator budget constraints to place pressure on demand for completions services through the end of the year and for the impact of the Permian pipeline capacity constraints to persist into 2019. While we do not provide hydraulic fracturing services in the Permian, we have seen the impact of the Permian slowdown in the Mid-Con and other regions, as hydraulic fracturing fleets migrate from the Permian to other basins, placing pressure on pricing. Additionally, we believe operators may slow completions activity around year-end holidays similar to 2017, which, when combined with budget constraints and Permian pipeline constraints, may reduce overall completions activity levels in the fourth quarter of 2018. We will continue to refine our cost structure and reposition assets with high utilization customers as market conditions evolve, and for now we do not plan to significantly reduce headcount for what we believe will be a temporary reduction in utilization. In 2019, we expect a rebound in completions activity from second half of 2018 levels as operators reload their E&P budgets and Permian pipeline capacity expands throughout 2019.
We view the horizontal rig count as a reliable indicator of the overall level of demand for our services, particularly directional drilling. According to Baker Hughes, horizontal rigs accounted for 84.5% of all total active rigs in the United States as of September 30, 2018, as compared to only 31.9% a decade earlier. Horizontal drilling allows E&P companies to drill wells with greater exposure to the economic payzone of a targeted formation, thus improving production. The advantages of horizontal drilling have increasingly led to greater demand for high-specification rigs that are more efficient in drilling shale oil and natural gas wells than older drilling rigs. Additionally, high-specification rigs which are capable of pad drilling operations have become more prevalent in North America and enable the operator to drill more wells per rig per year than older rigs. We believe that the increase in horizontal rigs and increased demand for high-specification rigs will drive demand for our experienced directional drilling personnel and modern equipment.
Completion of horizontal wells has evolved to require increasingly longer laterals and more hydraulic fracturing stages per horizontal well, which increases the exposure of the wellbore to the reservoir and improves production of the well. Hydraulic fracturing operations are conducted via a number of discrete stages along the lateral section of the wellbore. As wellbore lengths have increased, the number of hydraulic fracturing stages has continued to rise. According to Spears & Associates, from 2014 to 2016 the average number of stages per horizontal well increased from 23 stages per well to 34 stages per well, and is expected to further increase to an average of 48 stages per horizontal well in 2018. The market has also trended toward larger scale hydraulic fracturing operations, characterized by more hydraulic horsepower (“HHP”) per well. This requires a greater number of hydraulic fracturing units per fleet to execute a completion job. These trends, along with the overall expected recovery of U.S. drilling and completion activity, favor continued growth of the hydraulic fracturing sector. Spears & Associates forecasts that U.S. demand for HHP is expected to increase more than 112% from the fourth quarter of 2016 to the fourth quarter of 2018. As a result, we expect demand for our pressure pumping and wireline services to expand, including needs for our hydraulic fracturing and acidizing services, however pricing pressures resulting from increased competitive dynamics as new equipment enters the market have continued from last quarter into the third quarter 2018.
Demand for our pressure control services and wireline services are expected to grow along with increases in drilling and completions activity, increases in completions intensity and the increases in the average age of producing oil and natural gas wells. We believe that maintenance of unconventional wells will drive incremental demand for our coiled tubing, rig-assisted snubbing, nitrogen and fluid pumping services.

23


The markets we serve, and the oilfield services market in general, are characterized by fragmentation and consist of a large number of small independent operators serving these markets. We believe our relative scale is a differentiator, as we are a leading independent provider of directional drilling and pressure control services and have meaningful scale in both our pressure pumping and wireline services.
We are well positioned for the ongoing recovery we are observing in most of our service lines, all of which have already realized pricing improvement from the lows observed in 2016.
While we believe these trends will benefit us, our markets may be adversely affected by industry conditions that are beyond our control. For example, the overall decline in oil prices from their high levels in 2014 to their low levels in 2016 and the uncertainty regarding the sustainability of current oil prices has materially affected and may continue to materially affect the demand for our services and the rates that we are able to charge. Additionally, adverse weather conditions can affect the drilling and completion activities of our customers. During periods of heavy snow, high winds, ice or rain, the logistical capabilities of our suppliers may be delayed or we may be unable to move our equipment between locations, thereby reducing our ability to provide services and generate revenues. For example, inclement weather including freezing temperatures and high winds affected our available revenue generating hours during the first half of 2018.
The industry continues to encounter difficulties with logistics, vendor service quality and delivery times across various aspects of the third party supply chain, driven by continued growth in demand. We are proactively managing these transitory issues facing the entire industry to limit the impact to our customers and business. In addition, continued tightening of the labor market has result in higher wage rates, as well as increased recruiting, hiring, onboarding and training costs.
Results of Operations
Three Months Ended September 30, 2018 Compared to Three Months Ended September 30, 2017
The following tables provide selected operating data for the periods indicated (in thousands except Other Operational Data).
 
 
Three Months Ended
 
 
September 30, 2018
 
September 30, 2017
 
 
(Unaudited)
Revenues:
 
$
150,897

 
$
113,274

Costs and expenses:
 

 

Direct operating costs
 
118,525

 
89,910

General and administrative
 
22,540

 
18,613

Depreciation and amortization
 
12,033

 
11,238

Gain on disposition of assets
 
(629
)
 
(310
)
Operating loss
 
(1,572
)
 
(6,177
)
Non-operating income (expense):
 
 
 
 
       Interest expense
 
(574
)
 
(2,901
)
       Other income
 

 
724

Loss before income tax
 
(2,146
)
 
(8,354
)
Income tax expense
 
(207
)
 
(84
)
Net loss
 
$
(2,353
)
 
$
(8,438
)


24


 
 
Three Months Ended
 
 
September 30, 2018
 
September 30, 2017
 
 
(Unaudited)
Segment Adjusted EBITDA:
 
 
 
 
Directional Drilling
 
$
6,452

 
$
3,423

Pressure Pumping
 
5,795

 
5,791

Pressure Control
 
4,421

 
835

Wireline
 
(738
)
 
(1,166
)
Adjusted EBITDA (1)
 
$
12,898

 
$
6,772

Other Operational Data:
 
 
 
 
       Directional Drilling rig days (2)
 
4,874

 
3,711

       Average monthly Directional Drilling rigs on revenue (3)
 
77

 
61

       Total hydraulic fracturing stages
 
908

 
636

       Average hydraulic fracturing revenue per stage
 
$
50,119

 
$
56,530

 
(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 number of rigs earning revenues during a given time period, including days that standby revenues are earned.

Adjusted EBITDA
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 standup 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 September 30, 2018 and 2017 (in thousands of dollars):

25


 
Three Months Ended
 
September 30, 2018

September 30, 2017
Adjustments to reconcile Adjusted EBITDA to net loss:



Net loss
$
(2,353
)

$
(8,438
)
Income tax expense
207


84

Interest expense
574


2,901

Other income

 
(724
)
Depreciation and amortization expense
12,033


11,238

Gain on disposition of assets, net
(629
)

(310
)
Non-cash stock based compensation
2,569



Rebranding expense (1)
193


8

Settlement expense (2)
133


1,142

Severance expense (3)
74



Equipment and standup expense (4)
97


871

       Adjusted EBITDA
$
12,898


$
6,772

 
(1) 
Relates to expenses incurred in connection with rebranding our business segments.
(2) 
For 2017, represents professional fees related to investment banking, accounting and legal services associated with entering into the Former Term Loan that were recorded in general and administrative expenses. For 2018, represents lease buyouts, 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 in 2018 incurred in connection with a program implemented to reduce headcount in connection with the industry downturn. In our performance for the three months ended September 30, 2018, $0.1 million was recorded in general and administrative expenses.
(4) 
Relates to equipment standup costs incurred in connection with the mobilization and redeployment of assets. For 2017, primarily represents costs relating to the deployment of our third pressure pumping fleet, of which, $0.8 million was recorded in direct operating expenses and the remainder was recorded in general and administrative expenses. In our performance for the three months ended September 30, 2018, approximately $0.1 million was recorded in direct operating expenses related to a large diameter conversion of a coiled tubing unit.
Revenue. The following table provides revenues by segment for the periods indicated (in thousands of dollars):
 
 
Three Months Ended
 
 
September 30, 2018
 
September 30, 2017
Revenue:
 
 
 
 
       Directional Drilling
 
$
50,919

 
$
38,704

       Pressure Pumping
 
49,987

 
39,446

       Pressure Control
 
31,138

 
22,533

       Wireline
 
18,853

 
12,591

Total revenue
 
$
150,897

 
$
113,274

Revenue for the three months ended September 30, 2018 increased by $37.6 million, or 33.2%, to $150.9 million from $113.3 million for the three months ended September 30, 2017. The increase in revenue by business segment was as follows:
Directional Drilling revenue increased by $12.2 million, or 31.5%, to $50.9 million for the three months ended September 30, 2018, from $38.7 million for the three months ended September 30, 2017. This increase was primarily attributable to an 11.5% increase in utilization and a 3.2% increase in our day rate to $10,109. Approximately 95.0% of our Directional Drilling business segment revenue was derived from directional drilling and MWD activities for the three months ended September 30, 2018 compared to 93.0% for the three months ended September 30, 2017. The change in utilization and pricing accounted for 88.1% and 11.9% of the Directional Drilling revenue increase, respectively.
Pressure Pumping revenue increased by $10.6 million, or 26.9%, to $50.0 million for the three months ended September 30, 2018, from $39.4 million for three months ended September 30, 2017. This increase was primarily attributable to the mobilization of additional hydraulic fracturing spreads in February 2017, October 2017 and June 2018, which drove a 42.8% increase in stages to 908 for the three months ended September 30, 2018. Additionally, we experienced an 11.3% decrease in average revenue per stage to $50,119 for the three months ended September 30, 2018, from $56,530 for the three months ended September 30, 2017,

26


due to pricing pressure driven by the current competitive dynamics in the market, and a shift to more pump only job types completed. Approximately 91.0% of our Pressure Pumping business segment revenue was derived from hydraulic fracturing services for the three months ended September 30, 2018, compared to 91.4% for the three months ended September 30, 2017.
Pressure Control revenue increased by $8.6 million, or 38.2%, to $31.1 million for the three months ended September 30, 2018, from $22.5 million for the three months ended September 30, 2017. This increase was primarily attributable to 65.0% increase in weighted average revenue per day to $23,378 for the three months ended September 30, 2018, partially offset by a 2.1% decrease in weighted average utilization to 29.5%. In addition, increased well control activities and the deployment of converted large diameter coiled tubing units positively impacted Pressure Control revenue during the three months ended September 30, 2018.
Wireline revenue increased by $6.3 million, or 50.0%, to $18.9 million for the three months ended September 30, 2018, from $12.6 million for the three months ended September 30, 2017. The increase was primarily attributable to a 24.9% increase in utilization to 37.5% and a 33.2% increase in revenue per day to $12,132 for the three months ended September 30, 2018. Approximately 72.9% of our Wireline business segment revenue was derived from unconventional services for the three months ended September 30, 2018, compared to 67.8% for the three months ended September 30, 2017. The change in utilization and pricing accounted for 25.0% and 75.0% of the Wireline revenue change, respectively.
Direct operating expenses. The following table provides our direct operating expenses by business segment for the periods indicated (in thousands of dollars):
 
 
Three Months Ended
 
 
September 30, 2018
 
September 30, 2017
Direct operating expenses:
 
 
 
 
       Directional Drilling
 
$
38,651

 
$
30,743

       Pressure Pumping
 
40,362

 
31,169

       Pressure Control
 
23,148

 
17,517

       Wireline
 
16,364

 
10,481

Total direct operating expenses
 
$
118,525

 
$
89,910

Direct operating expenses for the three months ended September 30, 2018 increased by $28.6 million, or 31.8%, to $118.5 million, from $89.9 million for the three months ended September 30, 2017. The increase in direct operating expense was attributable to our business segments as follows:
Directional Drilling direct operating expenses increased by $8.0 million, or 26.1%, to $38.7 million for the three months ended September 30, 2018, from $30.7 million for the three months ended September 30, 2017. This increase was primarily attributable to a 31.3% increase in rig days to 4,874 over the same period, which in turn resulted in increased direct operating expenses for personnel and equipment.
Pressure Pumping direct operating expenses increased by $9.2 million, or 29.5%, to $40.4 million for the three months ended September 30, 2018, from $31.2 million for the three months ended September 30, 2017. This increase was primarily attributable to increased activity driven by a 42.8% increase in hydraulic fracturing stages completed to 908 stages compared to 636 stages completed in the prior period, which resulted in direct operating expense increases in materials, equipment and personnel costs. Additionally, Pressure Pumping placed incremental hydraulic fracturing fleets in service in October 2017 and June 2018 driving direct operating expenses higher in the three months ended September 30, 2018.
Pressure Control direct operating expenses increased by $5.6 million or 32.0%, to $23.1 million for the three months ended September 30, 2018, from $17.5 million for the three months ended September 30, 2017. This increase was primarily attributable to increased equipment and repair costs associated with an increase in coiled tubing and well control activities and rising direct labor costs as a result of increased activity levels and current market conditions for the three months ended September 30, 2018.
Wireline direct operating expenses increased by $5.9 million, or 56.2%, to $16.4 million for the three months ended September 30, 2018, from $10.5 million for the three months ended September 30, 2017. This increase was primarily attributable to increased market activity, including a 7.5% increase in utilization which resulted in increased 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 increased by $3.9 million, or 21.0%, to $22.5 million for the three months ended September 30, 2018, from $18.6 million for the three months ended September 30, 2017. The increase in general and administrative expenses was

27


primarily driven by stock based compensation expense of $2.6 million, increased headcount, additional administrative expenses related to being a publicly traded company and outsourced services for internal controls and tax consultancy compliance.
Depreciation and amortization. Depreciation and amortization increased by $0.8 million, or 7.1%, to $12.0 million for the three months ended September 30, 2018, from $11.2 million for the three months ended September 30, 2017. The increase in depreciation and amortization is primarily attributable to the additional deployed equipment currently in service.
Gain on disposition of assets, net. Net gain on disposition of assets for three months ended September 30, 2018 was $0.6 million, primarily attributable to Directional Drilling and Wireline’s gain on obsolete equipment disposals, offset by losses in other business segments, compared to a $0.3 million gain on disposition of assets, primarily attributable to the disposition of Pressure Pumping and Wireline assets for the three months ended September 30, 2017.
Interest expense. Interest expense decreased by $2.3 million, or approximately 79.3%, to $0.6 million for the three months ended September 30, 2018, compared to $2.9 million for the three months ended September 30, 2017. The decrease in interest expense was primarily due to higher debt levels, which exceeded $110.0 million in the prior period, compared to the current debt outstanding of $30.0 million as of September 30, 2018.
Adjusted EBITDA. Adjusted EBITDA for three months ended September 30, 2018 increased by $6.1 million, or 89.7% to $12.9 million from $6.8 million for the three months ended September 30, 2017. The change in Adjusted EBITDA by business segment was as follows:
Directional Drilling Adjusted EBITDA increased by $3.1 million, or 91.2%, to $6.5 million in the three months ended September 30, 2018, compared to $3.4 million in the three months ended September 30, 2017. The increase was primarily attributable to a 31.5% increase in revenue driven by increased market activity, partially offset by an associated 26.1% increase in direct operating costs.
Pressure Pumping Adjusted EBITDA of $5.8 million during the three months ended September 30, 2018, was consistent with the prior period. The nominal increase was primarily attributable to a 26.9% increase in revenue driven by increased hydraulic fracturing activity associated with the additional spreads added in February 2017, October 2017 and June 2018, which was offset by a 29.5% increase in direct operating expenses and a 5.6% increase in G&A expenses incurred as the business deployed additional equipment.
Pressure Control Adjusted EBITDA increased by $3.6 million, or 450.0% to $4.4 million in the three months ended September 30, 2018, compared to $0.8 million in the three months ended September 30, 2017. The increase was primarily attributable to a 38.2% increase in revenue driven by increased completions and well control activity, which was offset by a 32.0% increase in direct operating expenses and a 2.8% increase in G&A expense driven by increased personnel and materials.
Wireline Adjusted EBITDA increased by $0.5 million, or 41.7% to $(0.7) million in the three months ended September 30, 2018, compared to $(1.2) million in the three months ended September 30, 2017. The increase was primarily attributable to a 50.0% increase in revenue driven by increased pricing and utilization, partially offset by a 56.2% increase in direct operating expenses and a 3.8% decrease in G&A expense driven by increased personnel, consumables and overhead costs resulting from increased utilization.










28


Nine Months Ended September 30, 2018 Compared to nine Months Ended September 30, 2017
The following tables provide selected operating data for the periods indicated. (in thousands except Other Operational Data).
 
 
Nine Months Ended
 
 
September 30, 2018
 
September 30, 2017
 
 
(Unaudited)
Revenues:
 
$
444,701

 
$
307,170

Costs and expenses:
 

 

Direct operating costs
 
341,598

 
239,007

General and administrative
 
74,958

 
51,788

Depreciation and amortization
 
34,265

 
34,264

Gain on disposition of assets
 
(1,329
)
 
(2,300
)
Operating loss
 
(4,791
)
 
(15,589
)
Non-operating income (expense):
 
 
 
 
       Interest expense
 
(11,199
)
 
(8,290
)
       Other income
 

 
724

Loss before income tax
 
(15,990
)
 
(23,155
)
Income tax expense
 
(584
)
 
(69
)
Net loss
 
$
(16,574
)
 
$
(23,224
)

 
 
Nine Months Ended
 
 
September 30, 2018
 
September 30, 2017
 
 
(Unaudited)
Segment Adjusted EBITDA:
 
 
 
 
Directional Drilling
 
$
14,273

 
$
11,965

Pressure Pumping
 
24,569

 
17,283

Pressure Control
 
13,673

 
2,434

Wireline
 
2,614

 
(3,329
)
Adjusted EBITDA (1)
 
$
46,301

 
$
22,443

Other Operational Data:
 
 
 
 
       Directional Drilling rig days (2)
 
12,688

 
10,609

       Average monthly Directional Drilling rigs on revenue (3)
 
65

 
59

       Total hydraulic fracturing stages
 
2,816

 
1,937

       Average hydraulic fracturing revenue per stage
 
$
52,939

 
$
49,091

 

(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 number of rigs earning revenues during a time period, including days that standby revenues are earned.

Adjusted EBITDA
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 nine months ended September 30, 2018 and 2017 (in thousands of dollars):

29


 
 
Nine Months Ended
 
 
September 30, 2018
 
September 30, 2017
Adjustments to reconcile Adjusted EBITDA to net loss:
 
 
 
 
Net loss
 
$
(16,574
)
 
$
(23,224
)
Income tax expense
 
584

 
69

Interest expense
 
11,199

 
8,290

Other income
 

 
(724
)
Depreciation and amortization expense
 
34,265

 
34,264

Gain on disposition of assets, net
 
(1,329
)
 
(2,300
)
Non-cash stock based compensation
 
15,395

 

Rebranding expense (1)
 
248

 
10

Settlement expense (2)
 
522

 
3,494

Severance expense (3)
 
128

 
202

Equipment and standup expense(4)
 
1,863

 
2,362

       Adjusted EBITDA
 
$
46,301

 
$
22,443

 
(1) 
Relates to expenses incurred in connection with rebranding our business segments.
(2) 
For 2017, represents professional fees related to investment banking, accounting and legal services associated with entering into the Former Term Loan, of which $0.4 million was recorded in direct operating expenses and $3.1 million was recorded in general and administrative expenses. For 2018, represents lease buyouts, 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 in 2017 incurred in connection with a program implemented to reduce headcount in connection with the industry downturn, of which $0.2 million was recorded to direct operating expenses and a nominal amount was recorded to general and administrative expenses. In our performance for the nine months ended September 30, 2018, $0.1 million was recorded in general and administrative expenses.
(4) 
Relates to equipment standup costs incurred in connection with the mobilization and redeployment of assets. For 2017, primarily represents costs related to the deployment of our third hydraulic fracturing fleet, of which $2.2 million was recorded in direct operating expenses and $0.2 million was recorded in general and administrative expenses. In our performance for the nine months ended September 30, 2018, approximately $1.7 million was recorded in direct operating expenses and approximately $0.2 million was recorded in general and administration expenses for the deployment of our fourth hydraulic fracturing fleet and the large diameter conversion of coiled tubing units.
Revenue. The following table provides revenues by segment for the periods indicated (in thousands of dollars):
 
 
Nine Months Ended
 
 
September 30, 2018
 
September 30, 2017
Revenue:
 
 
 
 
       Directional Drilling
 
$
132,127

 
$
106,952

       Pressure Pumping
 
160,089

 
103,636

       Pressure Control
 
91,063

 
63,392

       Wireline
 
61,422

 
33,190

Total revenue
 
$
444,701

 
$
307,170

Revenue for the nine months ended September 30, 2018 increased by $137.5 million, or 44.8%, to $444.7 million from $307.2 million for the nine months ended September 30, 2017. The increase in revenue by business segment was as follows:
Directional Drilling revenue increased by $25.1 million, or 23.5%, to $132.1 million for the nine months ended September 30, 2018, from $107.0 million for the nine months ended September 30, 2017. This increase was primarily attributable to a 20.9% increase in utilization and a 4.9% increase in our day rate to $9,907. Approximately 95.0% of our Directional Drilling business segment revenue was derived from directional drilling and MWD activities for the nine months ended September 30, 2018 compared to 93.0% for the nine months ended September 30, 2017. The change in utilization and pricing accounted for 77.1% and 22.9% of the Directional Drilling revenue increase, respectively.
Pressure Pumping revenue increased by $56.5 million, or 54.5%, to $160.1 million for the nine months ended September 30, 2018, from $103.6 million for nine months ended September 30, 2017. This increase was primarily attributable to the mobilization of additional hydraulic fracturing spreads in February 2017, October 2017 and June 2018, which drove a 45.4% increase in stages

30


to 2,816 for the nine months ended September 30, 2018. Additionally, we experienced a 7.8% increase in average revenue per stage to $52,939 for the nine months ended September 30, 2018, from $49,091 for the nine months ended September 30, 2017, due to improved market conditions and shift in the job types completed. Approximately 93.2% of our Pressure Pumping business segment revenue was derived from hydraulic fracturing services for the nine months ended September 30, 2018, compared to 91.9% for the nine months ended September 30, 2017.
Pressure Control revenue increased by $27.7 million, or 43.7%, to $91.1 million for the nine months ended September 30, 2018, from $63.4 million for the nine months ended September 30, 2017. This increase was primarily attributable to a 7.5% increase in weighted average utilization to 30.7% and a 58.4% increase in weighted average revenue per day to $22,023 for the nine months ended September 30, 2018. In addition, higher well control activities and the deployment of incremental large diameter coiled tubing units positively impacted Pressure Control revenue during the nine months ended September 30, 2018.
Wireline revenue increased by $28.2 million, or 84.9%, to $61.4 million for the nine months ended September 30, 2018, from $33.2 million for the nine months ended September 30, 2017. The increase was primarily attributable to a 35.8% increase in utilization to 38.0% and a 50.8% increase in revenue per day to $12,672 for the nine months ended September 30, 2018. Approximately 78.9% of our Wireline business segment revenue was derived from unconventional services for the nine months ended September 30, 2018, compared to 67.9% for the nine months ended September 30, 2017. The change in utilization and pricing accounted for 26.5% and 73.5% of the Wireline revenue change, respectively.
Direct operating expenses. The following table provides our direct operating expenses by business segment for the periods indicated (in thousands of dollars):
 
 
Nine Months Ended
 
 
September 30, 2018
 
September 30, 2017
Direct operating expenses:
 
 
 
 
       Directional Drilling
 
$
102,721

 
$
83,083

       Pressure Pumping
 
125,565

 
79,054

       Pressure Control
 
65,860

 
49,991

       Wireline
 
47,452

 
26,879

Total direct operating expenses
 
$
341,598

 
$
239,007

Direct operating expenses for the nine months ended September 30, 2018 increased by $102.6 million, or 42.9%, to $341.6 million, from $239.0 million for the nine months ended September 30, 2017. The increase in direct operating expense was attributable to our business segments as follows:
Directional Drilling direct operating expenses increased by $19.6 million, or 23.6%, to $102.7 million for the nine months ended September 30, 2018, from $83.1 million for the nine months ended September 30, 2017. This increase was primarily attributable to a 19.6% increase in rig days to 12,688 over the same period, which in turn resulted in increased direct operating expenses for personnel and equipment.
Pressure Pumping direct operating expenses increased by $46.5 million, or 58.8%, to $125.6 million for the nine months ended September 30, 2018, from $79.1 million for the nine months ended September 30, 2017. This increase was primarily attributable to increased activity driven by a 45.4% increase in hydraulic fracturing stages completed to 2,816 stages compared to 1,937 stages completed in prior period, which resulted in direct operating expense increases in materials, equipment and personnel costs. Additionally, Pressure Pumping placed incremental hydraulic fracturing fleets in service in February 2017, October 2017 and June 2018 driving operating expenses higher.
Pressure Control direct operating expenses increased by $15.9 million, or 31.8%, to $65.9 million for the nine months ended September 30, 2018, from $50.0 million for the nine months ended September 30, 2017. This increase was primarily attributable to increased market activity, including a 7.5% increase in weighted average utilization, which resulted in increased costs associated with personnel, equipment and materials.
Wireline direct operating expenses increased by $20.6 million, or 76.6%, to $47.5 million for the nine months ended September 30, 2018, from $26.9 million for the nine months ended September 30, 2017. This increase was primarily attributable to increased market activity, including a 35.8% increase in utilization which resulted in increased costs associated with personnel, equipment and consumables.
General and administrative expenses. G&A expenses represent the costs associated with managing and supporting our operations. These expenses increased by $23.2 million, or 44.8%, to $75.0 million for the nine months ended September 30, 2018, from $51.8 million for the nine months ended September 30, 2017. The increase in general and administrative expenses was primarily driven by stock based compensation expense of $15.4 million which was recognized as a result our IPO. The increase in G&A was also

31


driven by additional administrative expenses related to being a publicly traded company and outsourced services for internal controls and tax consultancy compliance. Increases in headcount also contributed to the increase in G&A expenses during the first nine months of 2018.
In addition, audit fees relating to 2017 and outsourced services including internal controls and tax consultancy and compliance also contributed to the increase in the first quarter of 2018. Increases in headcount also contributed to the increase in G&A expenses during the nine months ended September 30, 2018.
Depreciation and amortization. Depreciation and amortization expense of $34.3 million for the nine months ended September 30, 2018 was consistent with the prior period. The depreciation and amortization expense is primarily attributed to the fully amortized trademarks and fully depreciated tools that are still in use.
Gain on disposition of assets, net. Net gain on disposition of assets for nine months ended September 30, 2018 was $1.3 million, primarily attributable to Directional Drilling and Wireline’s gain on idle equipment disposals, offset by losses in other business segments, compared to a $2.3 million gain on disposition of assets, primarily attributable to the disposition of Pressure Pumping and Wireline assets for the nine months ended September 30, 2017.
Interest expense. Interest expense increased by $2.9 million, or approximately 34.9%, to $11.2 million for the nine months ended September 30, 2018, compared to $8.3 million for the nine months ended September 30, 2017. The increase in interest expense was primarily due to debt extinguishment which resulted in the write-off of additional deferred financing costs of $1.9 million, discounts on the term loan of $5.3 million and a repayment premium of $1.3 million. The increase is partially offset by lower borrowings on the credit facility during the nine months ended September 30, 2018.
Adjusted EBITDA. Adjusted EBITDA for nine months ended September 30, 2018 increased by $23.9 million, or 106.7% to $46.3 million from $22.4 million for the nine months ended September 30, 2017. The change in Adjusted EBITDA by business segment was as follows:
Directional Drilling Adjusted EBITDA increased by $2.3 million, or 19.2%, to $14.3 million in the nine months ended September 30, 2018, compared to $12.0 million in the nine months ended September 30, 2017. The increase was primarily attributable to a 23.5% increase in revenue as a result of higher utilization and day rates. The EBITDA increase is offset by a 23.6% increase in direct operating costs and a 34.7% increase in G&A expenses due to increased activity levels and elevated motor rental expense primarily due to third-party maintenance turnaround time.
Pressure Pumping Adjusted EBITDA increased by $7.3 million, or 42.2% to $24.6 million in the nine months ended September 30, 2018, compared to $17.3 million in the nine months ended September 30, 2017. The increase was primarily attributable to a 54.5% increase in revenue driven by increased hydraulic fracturing activity, which was partially offset by a 58.8% increase in direct operating expenses and a 22.9% increase in G&A expenses incurred as the business deployed additional equipment, including the fourth hydraulic fracturing fleet.
Pressure Control Adjusted EBITDA increased by $11.3 million, or 470.8% to $13.7 million in the nine months ended September 30, 2018, compared to $2.4 million in the nine months ended September 30, 2017. The increase was primarily attributable to a 43.7% increase in revenue driven by increased completions and well control activity, which was offset by a 31.8% increase in direct operating expenses and a 14.0% increase in G&A expense driven by increased personnel, materials and overhead costs.
Wireline Adjusted EBITDA increased by $5.9 million, or 178.8% to $2.6 million in the nine months ended September 30, 2018, compared to $(3.3) million in the nine months ended September 30, 2017. The increase was primarily attributable to an 84.9% increase in revenue driven by increased pricing and utilization, partially offset by a 76.6% increase in direct operating expenses and a 19.6% increase in G&A expense driven by increased personnel, consumables and overhead costs resulting from increased utilization.
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 our former revolving credit facility (the “Former Revolving Credit Facility”), our former $40.0 million term loan (the “Former Term Loan”), the New ABL Facility (as defined below) and cash flows from operations. At September 30, 2018, we had $22.1 million of cash and equivalents and $47.7 million available to draw on the New ABL Facility, which resulted in a total liquidity position of $69.8 million.
As our drilling and completion activity has increased with the rise in commodity prices since 2016, our cash flow from operations has begun to improve and we expect cash flow to continue to improve if drilling and completion activity continues to increase. However, there is no certainty that cash flow will continue to improve or that we will have positive operating cash flow for a

32


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 has been for 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 dollars) presented below:

 
 
Nine Months Ended
 
 
September 30, 2018
 
September 30, 2017
Net cash provided by (used in) operating activities
 
$
36,984

 
$
(18,442
)
Net cash provided by (used in) investing activities
 
(46,276
)
 
20,160

Net cash provided by (used in) financing activities
 
22,611

 
(6,148
)
Net change in cash
 
13,319

 
(4,430
)
Cash balance end of period
 
$
22,070

 
$
7,789

Net cash provided by (used in) operating activities
Net cash provided by operating activities was $37.0 million for the nine months ended September 30, 2018, compared to net cash used in operations of $18.4 million for nine months ended September 30, 2017. The 2018 increase in operating cash flows was primarily attributable to the faster collection of trade receivables and improved performance compared to the lower utilization and pricing experienced in 2017 as a result of prevailing market conditions.
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 available cash.
Net cash provided by (used in) investing activities
Net cash used in investing activities was $46.3 million for nine months ended September 30, 2018, compared to net cash provided by investing activities of $20.2 million for the nine months ended September 30, 2017. The cash flow used in investing activities for the nine months ended September 30, 2018 was primarily used on our existing fleet capital spending, to activate our fourth hydraulic fracturing spread, and coiled tubing unit conversions, compared to the net cash provided by divestiture activities in 2017.

We used $53.1 million to purchase equipment and we received $6.8 million in exchange for selling assets for the nine months ended September 30, 2018, as compared to the nine months ended September 30, 2017, when we used $13.5 million of cash to purchase equipment and received $33.7 million in exchange for selling assets.
Net cash provided by (used in) financing activities
Net cash provided by financing activities was $22.6 million for nine months ended September 30, 2018, compared to net cash used in financing activities of $6.1 million for the nine months ended September 30, 2017. 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 totaling $90.5 million, which was offset by the repayments under our Former Revolving Credit Facility and Former Term Loan, which totaled $92.3 million. In connection with the settlement of the Former Term Loan, a prepayment fee of 3%, or approximately $1.3 million was paid. Additionally, $1.3 million was paid for treasury shares in connection with the settlement of equity based compensation, net of taxes, which vested during the nine months ended September 30, 2018.
Our Credit Facility
Former Revolving Credit Facility
The Company 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 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

33


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
The Company also had a four-year, $40.0 million term loan agreement 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 $6.75 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 $1.3 million was paid. The prepayment fee is recorded as a loss on extinguishment 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.
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, 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 the borrowing capacity was $77.6 million and $13.0 million was immediately drawn. The loan interest rate on the borrowings outstanding at September 30, 2018, was 4.8% and $30.0 million was outstanding under the New ABL Facility as of September 30, 2018.

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 Borrowers’ 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 the Borrowers or any credit party; and (iv) the occurrence of a default under any other material indebtedness the Borrowers 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 September 30, 2018, we were in compliance with our debt covenants.
Capital Requirements and Sources of Liquidity
During the nine months ended September 30, 2018, our capital expenditures, excluding acquisitions, were approximately $10.2 million, $26.0 million, $15.4 million and $1.5 million in Directional Drilling, Pressure Pumping, Pressure Control and Wireline business segments, respectively, for aggregate net capital expenditures of approximately $53.1 million, primarily for the activation of our fourth hydraulic fracturing spreads, conversions of two coiled tubing units and maintenance capital expenditures on existing equipment.

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For the nine months ended September 30, 2017, our capital expenditures, excluding acquisitions, were approximately $6.4 million, $2.0 million, $4.8 million and $0.3 million in our Directional Drilling, Pressure Pumping, Pressure Control and Wireline business segments for aggregate net capital expenditures of approximately $13.5 million, primarily for purchase of new drilling motors, the redeployment of a hydraulic fracturing fleet and maintenance capital expenditures.
Consistent with our previously disclosed 2018 capital expenditures forecast, we currently estimate that our capital expenditures for our existing fleets and approved capacity additions during the remainder of 2018 will range from $18.5 million to $21.0 million, approximately $4.0 million to $5.0 million to invest in large diameter coiled tubing units and the remainder for maintenance and other growth capital expenditures. 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 the proceeds from the IPO, our operating cash flow and available borrowings under our New ABL Facility will be sufficient to fund our operations for the next twelve months. As drilling and completion activity in the United States has increased with the rise in commodity prices since 2016, our cash flow from operations has begun to improve and we expect cash flow to continue to improve if drilling and completion activity continues to increase. However, 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 capital expenditures acquisition budget for 2018 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, at the Company’s discretion.  As of September 30, 2018, no repurchases had been made under this program.
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 September 30, 2018.
Critical Accounting Policies
Other than the accounting impacts resulting from our adoption of ASC 606, which are discussed in Notes 2 and 10 to our condensed consolidated financial statements herein, as of September 30, 2018, 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, 2017, filed with the SEC on March 30, 2018.
Recent Accounting Pronouncements
See Note 2 to our condensed consolidated financial statements for a discussion of recently issued accounting pronouncements.
Item 3.
Quantitative and Qualitative Disclosures About Market Risk.
The demand, pricing and terms for oil and gas services provided by us are largely dependent upon the level of activity for the U.S. oil and natural gas industry. Industry conditions are influenced by numerous factors over which we have no control, including, but not limited to: the supply of and demand for oil and natural gas; the prices and expectations about future prices of oil and natural gas; the cost of exploring for, developing, producing and delivering oil and natural gas; the expected rates of declining current production; the discovery rates of new oil and natural gas reserves; available pipeline and other transportation capacity; weather conditions; domestic and worldwide economic conditions; political instability in oil-producing countries; environmental regulations; technical advances affecting energy consumption; the price and availability of alternative fuels; the ability of oil and natural gas producers to raise equity capital and debt financing; and merger and divestiture activity among oil and natural gas producers.

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The level of activity in the U.S. oil and natural gas E&P industry is volatile. Expected trends in oil and natural gas production activities may not continue and demand for our services may not reflect the level of activity in the industry. Any prolonged substantial reduction in oil and natural gas prices would likely affect oil and natural gas production levels and therefore affect demand for our services. A material decline in oil and natural gas prices or U.S. activity levels could have a material adverse effect on our business, financial condition, results of operations and cash flow. Demand for our services has continued to improve since May 2016 after our industry experienced a significant downturn beginning in late 2014. Our improving outlook in both activity levels and margin performance are based on our relative scale and strong positioning in each of our four business segments. Should oil and gas prices again decline, the demand for the services we offer could be negatively impacted.
Inflation
Inflation in the United States has been relatively low in recent years and did not have a material impact on our results of operations for the three months ended September 30, 2018 and 2017, respectively. Although the impact of inflation has been insignificant in recent years, it is still a factor in the U.S. economy and we tend to experience inflationary pressure on the cost of oilfield services and equipment as increasing oil and gas prices increase drilling activity in our areas of operations and the rest of equipment, materi