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 SeptemberJune 30, 20182019
or
☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Commission file number 001-38183
ranger_logoa13.jpg
RANGER ENERGY SERVICES, INC.
(Exact name of registrant as specified in its charter)
Delaware81‑5449572
(State or other jurisdiction of
incorporation or organization)
(I.R.S. Employer
Identification No.)
800 Gessner Street, Suite 1000
Houston, Texas 77024
(Address of principal executive offices) (Zip Code)
(713) 935‑8900
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
Title of each classTrading Symbol(s)Name of each exchange on which registered
Class A Common Stock, $0.01 par valueRNGRNew York Stock Exchange

Indicate by check mark whether the registrantregistrant: (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 Exchange Act). Yes ☐ No ☒
As of November 1, 2018,July 24, 2019, the registrant had 8,929,4308,717,026 shares of Class A Common Stock and 6,866,154 shares of Class B Common Stock outstanding.

RANGER ENERGY SERVICES, INC.
TABLE OF CONTENTS
  Page
PART I – FINANCIAL INFORMATION
  
Item 1. Financial Statements
  
Unaudited Interim Condensed Consolidated Balance Sheets
 
3
Unaudited Interim Condensed Consolidated Statements of Operations
 
4
Unaudited Interim Condensed Consolidated Statements of Stockholders’ Equity
5
Unaudited Interim Condensed Consolidated Statements of Cash Flows
 
56
Notes to Unaudited Interim Condensed Consolidated Financial Statements
 
67
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
 
19
Item 3. Quantitative and Qualitative Disclosures About Market RiskRisks
 
3432
Item 4. Controls and Procedures
 
3433
   
PART II – OTHER INFORMATION
  
Item 1. Legal Proceedings
 
3534
Item 1A. Risk Factors
 
3534
Item 2. Unregistered Sales of Securities and Use of Proceeds
34
Item 6. Exhibits
 
35
   
SIGNATURES
 
3736


PART I – FINANCIAL INFORMATION
ITEM 1. Financial Statements
RANGER ENERGY SERVICES, INC.
UNAUDITED INTERIM CONDENSED CONSOLIDATED BALANCE SHEETS
(in millions, except share and per share amounts)
 September 30,
2018		 December 31,
2017		 June 30, 2019 December 31, 2018
Assets        
Current assets    
Cash and cash equivalents $2.0
 $5.3
 $1.7
 $2.6
Accounts receivable, net 49.7
 32.1
 54.0
 45.4
Unbilled revenues 4.2
 6.0
Prepaid expenses and other current assets 7.1
 5.7
Assets held for sale 0.6
 0.6
Contract assets 6.0
 3.1
Inventory 7.7
 4.9
Prepaid expenses 3.7
 5.1
Total current assets 63.6
 49.7
 73.1
 61.1
Property, plant and equipment, net 230.7
 189.2
Goodwill —
 9.0
    
Property and equipment, net 227.7
 229.8
Intangible assets, net 10.2
 10.8
 9.7
 10.0
Operating lease right-of-use assets 6.7
 —
Other assets 0.5
 1.0
 0.7
 1.6
Total assets $305.0
 $259.7
 $317.9
 $302.5
    
Liabilities and Stockholders' Equity        
Current liabilities    
Accounts payable $30.2
 $32.0
 $15.0
 $17.2
Accrued expenses 27.1
 11.6
 19.8
 18.5
Capital lease obligations, current portion 3.9
 8.0
Finance lease obligations, current portion 4.8
 4.4
Long-term debt, current portion 11.3
 1.3
 15.8
 15.8
Other current liabilities 3.0
 —
 2.5
 3.0
Total current liabilities 75.5
 52.9
 57.9
 58.9
Capital lease obligations 6.5
 1.5
Long-term debt 32.8
 5.8
    
Operating lease right-of-use obligations 4.6
 —
Finance lease obligations 4.8
 6.6
Long-term debt, net 47.8
 44.7
Other long-term liabilities 0.5
 3.8
 0.7
 0.3
Total liabilities 115.3
 64.0
 115.8
 110.5
Commitments and contingencies (Note 16) 
 
    
Commitments and contingencies (Note 13) 
 
    
Stockholders' equity        
Preferred stock, $0.01 per share; 50,000,000 shares authorized, no shares issued or outstanding as of September 30, 2018 and December 31, 2017 —
 —
Class A Common Stock, $0.01 par value, 100,000,000 shares authorized, 8,941,374 shares issued and outstanding as of September 30, 2018 and 8,413,178 shares issued and outstanding as of December 31, 2017 0.1
 0.1
Class B Common Stock, $0.01 par value, 100,000,000 shares authorized, 6,866,154 shares issued and outstanding as of September 30, 2018 and December 31, 2017 0.1
 0.1
Preferred stock, $0.01 per share; 50,000,000 shares authorized; no shares issued or outstanding as of June 30, 2019 and December 31, 2018 —
 —
Class A Common Stock, $0.01 par value, 100,000,000 shares authorized; 8,717,026 and 8,448,527 shares issued and outstanding as of June 30, 2019 and December 31, 2018, respectively 0.1
 0.1
Class B Common Stock, $0.01 par value, 100,000,000 shares authorized; 6,866,154 shares issued and outstanding as of June 30, 2019 and December 31, 2018 0.1
 0.1
Accumulated deficit (11.0) (6.6) (6.9) (9.9)
Additional paid-in capital 111.2
 110.1
 119.9
 111.6
Total stockholders' equity 100.4
 103.7
 113.2
 101.9
Non-controlling interest 89.3
 92.0
 88.9
 90.1
Total stockholders' equity 189.7
 195.7
 202.1
 192.0
Total liabilities and stockholders' equity $305.0
 $259.7
 $317.9
 $302.5
The accompanying notes are an integral part of these unaudited interim condensed consolidated financial statements.

RANGER ENERGY SERVICES, INC.
UNAUDITED INTERIM CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(in millions, except share and per share amounts)
 Three Months Ended Six Months Ended
 Three Months Ended
September 30,		 Nine Months Ended
September 30,		 June 30, June 30,
 2018 2017 2018 2017 2019 2018 2019 2018
Revenues                
Well Services $78.1
 $39.0
 $206.9
 $97.9
Processing Solutions 4.0
 2.1
 10.9
 5.9
High specification rigs $33.1
 $39.6
 $64.8
 $75.9
Completion and other services 46.3
 29.5
 97.9
 52.9
Processing solutions 4.9
 4.0
 9.9
 6.9
Total revenues 82.1
 41.1
 217.8
 103.8
 84.3
 73.1
 172.6
 135.7
        
Operating expenses                
Cost of services (exclusive of depreciation and amortization shown separately):        
Well Services 61.8
 33.1
 167.7
 81.1
Processing Solutions 1.8
 0.8
 5.1
 2.2
Cost of services (exclusive of depreciation and amortization):        
High specification rigs 28.7
 33.6
 56.1
 65.1
Completion and other services 35.0
 21.8
 72.9
 40.2
Processing solutions 1.9
 1.9
 4.1
 3.3
Total cost of services 63.6
 33.9
 172.8
 83.3
 65.6
 57.3
 133.1
 108.6
General and administrative 6.6
 7.9
 20.8
 24.0
 6.3
 7.8
 13.5
 14.8
Depreciation and amortization 7.5
 4.1
 20.6
 11.7
 8.4
 7.0
 16.8
 13.1
Impairment of goodwill —
 —
 9.0
 —
 —
 —
 —
 9.0
Total operating expenses 77.7
 45.9
 223.2
 119.0
 80.3
 72.1
 163.4
 145.5
        
Operating income (loss) 4.4
 (4.8) (5.4) (15.2) 4.0
 1.0
 9.2
 (9.8)
        
Other expenses                
Interest expense, net (0.9) (4.3) (1.8) (5.9) 1.9
 0.5
 3.2
 0.9
Total other expenses (0.9) (4.3) (1.8) (5.9) 1.9
 0.5
 3.2
 0.9
        
Income (loss) before income tax expense 3.5
 (9.1) (7.2) (21.1) 2.1
 0.5
 6.0
 (10.7)
Tax expense (benefit) (0.5) 0.4
 0.3
 0.4
Tax expense 0.3
 1.7
 0.6
 0.8
Net income (loss) 4.0
 (9.5) (7.5) (21.5) 1.8
 (1.2) 5.4
 (11.5)
Less: Net loss attributable to the Predecessor —
 (3.2) —
 (15.2)
Less: Net income (loss) attributable to non-controlling interests 1.9
 (2.8) (3.2) (2.8) 0.8
 (0.5) 2.4
 (5.1)
Net income (loss) attributable to Ranger Energy Services, Inc. $2.1
 $(3.5) $(4.3) $(3.5) $1.0
 $(0.7) $3.0
 $(6.4)
        
Earnings (loss) per common share                
Basic $0.24
 $(0.42) $(0.48) $(0.42) $0.12
 $(0.08) $0.35
 $(0.76)
Diluted $0.23
 $(0.42) $(0.48) $(0.42) $0.11
 $(0.08) $0.32
 $(0.76)
Weighted average common shares outstanding                
Basic 8,910,260
 8,413,178
 8,897,319
 8,413,178
 8,514,495
 8,414,557
 8,481,788
 8,413,871
Diluted 9,156,872
 8,413,178
 8,897,319
 8,413,178
 9,491,684
 8,414,557
 9,458,977
 8,413,871
The accompanying notes are an integral part of these unaudited interim condensed consolidated financial statements.


RANGER ENERGY SERVICES, INC.
UNAUDITED INTERIM CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
(in millions, except share amounts)
 Three Months Ended June 30, Six Months Ended June 30,
 2019201820192018 2019201820192018
 QuantityAmount QuantityAmount
Shares, Class A Common Stock         
Balance, beginning of period8,454,273
8,413,178
$0.1
$0.1
 8,448,527
8,413,178
$0.1
$0.1
Issuance of shares under share-based compensation plans93,621
4,648
—
—
 101,621
4,648
—
—
Shares withheld for taxes on equity transactions(37,765)(1,185)—
—
 (40,019)(1,185)—
—
Issuance of Class A Common Stock to related party206,897
—
—
—
 206,897
—
—
—
Balance, end of period8,717,026
8,416,641
$0.1
$0.1
 8,717,026
8,416,641
$0.1
$0.1
          
Shares, Class B Common Stock         
Balance, beginning of period6,866,154
6,866,154
$0.1
$0.1
 6,866,154
6,866,154
$0.1
$0.1
Balance, end of period6,866,154
6,866,154
$0.1
$0.1
 6,866,154
6,866,154
$0.1
$0.1
          
Accumulated deficit         
Balance, beginning of period  $(7.9)$(12.3)   $(9.9)$(6.6)
Net income (loss) attributable to controlling interest  1.0
(0.7)   3.0
(6.4)
Balance, end of period  $(6.9)$(13.0)   $(6.9)$(13.0)
          
Additional paid-in capital         
Balance, beginning of period  $112.2
$110.1
   $111.6
$110.1
Equity based compensation amortization  0.8
0.4
   1.4
0.4
Shares withheld for taxes on equity transactions  (0.4)—
   (0.4)—
Issuance of Class A Common Stock to related party  3.0
—
   3.0
—
Benefit from reversal of valuation allowance  0.6
—
   0.6
—
Impact of transactions affecting noncontrolling interest  3.7
—
   3.7
—
Balance, end of period  $119.9
$110.5
   $119.9
$110.5
          
Total controlling interest shareholders’ equity         
Balance, beginning of period  $104.5
$98.0
   $101.9
$103.7
Net income (loss) attributable to controlling interest  1.0
(0.7)   3.0
(6.4)
Benefit from reversal of valuation allowance  0.6
—
   0.6
—
Equity based compensation amortization  0.8
0.4
   1.4
0.4
Shares withheld for taxes on equity transactions  (0.4)—
   (0.4)—
Issuance of Class A Common Stock to related party  3.0
—
   3.0
—
Impact of transactions affecting noncontrolling interest  3.7
—
   3.7
—
Balance, end of period  $113.2
$97.7
   $113.2
$97.7
          
Noncontrolling interest         
Balance, beginning of period  $91.7
$87.6
   $90.1
$92.0
Net income (loss) attributable to noncontrolling interest  0.8
(0.5)   2.4
(5.1)
Equity based compensation amortization  0.1
0.3
   0.1
0.5
Impact of transactions affecting noncontrolling interest  (3.7)—
   (3.7)—
Balance, end of period  $88.9
$87.4
   $88.9
$87.4
          
Total Equity         
Balance, beginning of period  $196.2
$185.6
   $192.0
$195.7
Total income (loss)  1.8
(1.2)   5.4
(11.5)
Benefit from reversal of valuation allowance  0.6
—
   0.6
—
Equity based compensation amortization  0.9
0.7
   1.5
0.9
Shares withheld for taxes on equity transactions  (0.4)—
   (0.4)—
Issuance of Class A Common Stock to related party  3.0
—
   3.0
—
Balance, end of period  $202.1
$185.1
   $202.1
$185.1
The accompanying notes are an integral part of these unaudited interim condensed consolidated financial statements.

RANGER ENERGY SERVICES, INC.
UNAUDITED INTERIM CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(in millions)
  Nine Months Ended
September 30,
  2018 2017
Cash Flows from Operating Activities    
Net loss $(7.5) $(21.5)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:    
Depreciation and amortization 20.6
 11.7
Issuance of Class A and Class B Common Stock for settlement of interest on related party debt —
 5.2
Bad debt expense 0.2
 0.2
Impairment of goodwill 9.0
 —
Equity based compensation amortization 1.6
 0.9
Gain on sale of property, plant and equipment (0.2) —
Changes in operating assets and liabilities, net of effect of acquisitions    
Accounts receivable (17.7) (5.1)
Unbilled revenue 1.7
 (1.8)
Prepaid expenses and other current assets (1.3) (4.9)
Other assets 0.4
 (0.7)
Accounts payable 8.4
 1.5
Accounts payable - related party —
 (2.4)
Accrued expenses 10.7
 9.4
Other long-term liabilities (1.0) (0.1)
Net cash provided by (used in) operating activities 24.9
 (7.6)
Cash Flows from Investing Activities    
Purchase of property, plant and equipment (56.1) (16.4)
Proceeds from sale of property, plant and equipment 4.0
 —
Acquisition, net of cash received (4.0) (47.7)
Net cash used in investing activities (56.1) (64.1)
Cash Flows from Financing Activities    
Borrowings under line of credit agreement, net of deferred costs 41.8
 —
Borrowings on long-term debt, net of deferred costs 21.3
 —
Proceeds from the Offering, net of underwriters' expense of $4.2 million —
 80.8
Borrowings on related party debt —
 21.0
Payments on line of credit agreement and long-term debt (25.6) (12.0)
Principal payments on capital lease obligations (9.6) (0.8)
Payments incurred for the Offering —
 (3.9)
Contributions from parent —
 4.0
Net cash provided by financing activities 27.9
 89.1
Increase (decrease) in Cash and Cash equivalents (3.3) 17.4
Cash, Cash Equivalents and Restricted Cash, Beginning of Year 5.3
 3.2
Cash, Cash Equivalents and Restricted Cash, End of Year $2.0
 $20.6
Supplemental Cash Flow Information    
Interest paid $(1.3) $(0.5)
Supplemental Disclosure of Non-cash Investing and Financing Activity    
Non-cash capital expenditures $5.3
 $(15.6)
Non-cash additions to fixed assets through capital lease financing $(10.4) $(9.0)
Issuance of Class A and Class B Common Stock for payment of related party debt $—
 $(21.0)
Issuance of Class A Common Stock for acquisition $—
 $(5.0)
Seller's Notes for payment of acquisition $—
 $(7.0)
  Six Months Ended
  June 30,
  2019 2018
Cash Flows from Operating Activities    
Net income (loss) $5.4
 $(11.5)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:    
Depreciation and amortization 16.8
 13.1
Impairment of goodwill —
 9.0
Equity based compensation 1.5
 1.0
(Gain) loss on sale of property, plant and equipment (0.3) 0.4
Other costs, net 0.3
 0.2
Changes in operating assets and liabilities, net of effect of acquisitions    
Accounts receivable (8.6) (11.4)
Contract assets (2.9) 2.6
Inventory (2.8) (2.3)
Prepaid expenses 1.4
 1.1
Other assets 0.9
 0.7
Accounts payable (0.6) 3.7
Accrued expenses 2.0
 5.8
Other long-term liabilities 1.1
 (0.3)
Net cash provided by operating activities 14.2
 12.1
     
Cash Flows from Investing Activities    
Purchase of property, plant and equipment (16.0) (34.1)
Proceeds from sale of property, plant and equipment 0.5
 3.6
Acquisitions, net of cash received —
 (4.0)
Net cash used in investing activities (15.5) (34.5)
     
Cash Flows from Financing Activities    
Borrowings under line of credit facility 25.1
 27.7
Principal payments on line of credit facility (17.3) —
Borrowings on Encina Master Financing Agreement, net of deferred financing costs —
 22.0
Principal payments on Encina Master Financing Agreement (4.8) (13.5)
Principal payments on financing lease obligations (2.2) (8.6)
Shares withheld on equity transactions (0.4) —
Net cash provided by financing activities 0.4
 27.6
     
Increase (decrease) in Cash and Cash equivalents (0.9) 5.2
Cash and Cash Equivalents, Beginning of Period 2.6
 5.3
Cash and Cash Equivalents, End of Period $1.7
 $10.5
     
Supplemental Cash Flows Information    
Interest paid $2.3
 $0.4
Supplemental Disclosure of Non-cash Investing and Financing Activity    
Non-cash capital expenditures $(2.3) $(10.2)
Non-cash additions to fixed assets through financing leases $(0.8) $(5.9)
Initial non-cash operating lease right-of-use asset additions $(8.3) $—
Issuance of Class A Common Stock to related party $3.0
 $—
The accompanying notes are an integral part of these unaudited interim condensed consolidated financial statements.

RANGER ENERGY SERVICES, INC.
NOTES TO UNAUDITED INTERIM CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Note 1 — Organization and Business Operations
Organization
Ranger Energy Services, LLC (“Ranger Services”) was, through Ranger Energy Holdings, LLC (“Ranger Holdings”), formed by CSL Capital Management, LLC (“CSL”) in June 2014 as a provider of high‑spec well service rigs and associated services. Torrent Energy Services, LLC (“Torrent Services” and together with Ranger Services, the “Predecessor Companies”) was, through Torrent Energy Holdings, LLC (“Torrent Holdings”), acquired by CSL in September 2014 as a provider of proprietary, modular equipment for the processing of natural gas. In June 2016, CSL indirectly acquired substantially all of the assets of Magna Energy Services, LLC (“Magna”), a provider of well services and wireline services, which it contributed to Ranger Services in September 2016. In October 2016, Ranger Services acquired substantially all of the assets of Bayou Workover Services, LLC (“Bayou”), an owner and operator of high‑spec well service rigs. These unaudited interim condensed consolidated financial statements included in this quarterly report present (i) prior to August 16, 2017, the historical financial information of Ranger Services, Torrent Services, Magna and Bayou (collectively, the “Predecessor”), and (ii) subsequent to August 16, 2017, the historical information of Ranger Energy Services, Inc. (“Ranger” or the “Company”).
Ranger was incorporated as a Delaware corporation in February 2017. In conjunction with Ranger’s initial public offering (the “Offering”) of Class A common stock, par value $0.01 per share (“Class A Common Stock”), which closed on August 16, 2017 and the corporate reorganization described below, Ranger is a holding company, the sole material assets of which consist of membership interests in RNGR Energy Services, LLC, a Delaware limited liability company (“Ranger LLC”). Ranger LLC owns all of the outstanding equity interests in Ranger Energy Services, LLC (“Ranger Services”) and Torrent Energy Services, LLC (“Torrent Services”), the subsidiaries through which it operates its assets. Through consummation of the corporate reorganization, Ranger LLC is the sole managing member of Ranger Services and Torrent Services, and is responsible for all operational, management and administrative decisions relating to Ranger Services and Torrent Services’ business and consolidates the financial results of Ranger Services and Torrent Services and their subsidiaries.
Reorganization
On August 10, 2017, Ranger Services, entered into a Master Reorganization Agreement (the “Master Reorganization Agreement”) with, among others, Ranger LLC, Ranger Energy Holdings LLC, Ranger Energy Holdings II, LLC, a Delaware limited liability company (“RangerTorrent Energy Holdings, II”), Torrent HoldingsLLC and Torrent Energy Holdings II, LLC, a Delaware limited liability company (“Torrent Holdings II”) and, togetherLLC. In connection with Ranger Holdings, Ranger Holdings II and Torrent Holdings (the “Existing Owners”).
Subject to the terms and conditions set forth in the Master Reorganization Agreement, the parties thereto effected a series of restructuring transactions in connection with the Offering of Class A Common Stock, as a result of which:
(i) Ranger Holdings II and Torrent Holdings II contributed certain of the equity interests in the Predecessor Companies to the Company in exchange for an aggregate of 1,683,386 shares of Class A Common Stock and the Company contributed such equity interests to Ranger LLC in exchange for 1,638,386 units in Ranger LLC (“Ranger Units”). Additionally, an aggregate of $3.0 million willto be paid by the Company to CSL Energy Holdings I, LLC, a Delaware limited liability company and CSL Energy Holdings II, LLC, a Delaware limited liability company, on or prior to the 18-month anniversary of the consummation of the OfferingCompany’s initial public offering (the “Offering”) in, at the Company’s option, cash, shares of Class A Common Stock (with such shares to be valued based on the greater of the price of the Class A Common Stock in the Offering and a 30-day volume-weightedweighted average price) or a combination thereof;
(ii) Ranger Holdingsthereof (included within Other current liabilities on the accompanying consolidated balance sheet as of December 31, 2018). During the three and Torrent Holdings contributedsix months ended June 30, 2019, the remaining membership interests inCompany settled the Predecessor Companies to Ranger LLC in exchange$3.0 million liability. See Note 9 — Equity for 5,621,491 units in Ranger Units and 5,621,491 sharesfurther details of the Company’s Class B common stock, par value $0.01 per share (“Class B Common Stock” and together with the Class A Common Stock, “Common Stock”), which the Company initially issued and contributed to Ranger LLC;
(iii) the Company contributed all of the net proceeds received by it in the Offering to Ranger LLC in exchange for 5,862,069 Ranger Units;
(iv) Ranger LLC distributed to each of Ranger Holdings and Torrent Holdings one share of Class B Common Stock received pursuant to (ii) above for each Ranger Unit such Existing Owner held; and
(v) as consideration for the termination of certain loan agreements, the Company issued 567,895 shares of Class A Common Stock (in connection with which Ranger LLC issued 567,895 Ranger Units to the Company) and Ranger LLC issued an aggregate of 1,244,663 Ranger Units (and distributed a corresponding number of shares of Class B Common Stock) to the lenders thereof.
The foregoing transactions were undertaken in reliance on an exemption from the registration requirements of the Securities Act of 1933, as amended (the “Securities Act”), pursuant to Section 4(a)(2) thereof. As a result of these transactions, Ranger LLC became a subsidiary of the Company and the Predecessor Companies became wholly owned subsidiaries of Ranger LLC.


Initial Public Offering
On August 16, 2017, the Company completed the Offering of 5,862,069 shares of our Class A Common Stock. The gross proceeds of the Offering to the Company, based on a public offering price of $14.50 per share, were $85.0 million, which resulted in net proceeds to the Company of $77.0 million, after deducting $4.2 million of underwriting discounts and commissions and $3.9 million of costs related to the Offering. These net proceeds were used to pay off the remainder of its long term debt of $10.4 million, fund $45.2 million for the cash portion of the ESCO Acquisition (as defined herein) and pay $0.7 million for cash bonuses to certain employees. The remaining $20.7 million of net proceeds were used to fund capital expenditures and general business expenses.equity position.
Business
The Company is one of the largest providers of high specification (“high‑specspec”) well service rigs and complimentaryassociated services in the United States, with a focus on technically demanding unconventional horizontal well completion and production operations. The Company’sWe believe that our fleet of 141 well service rigs is among the newest and most advanced in the industry and, based on our historical rig utilization and feedback from our customers, we believe that we are an operator of choice for U.S. onshore exploration and production (“E&P”) companies that require completion and production services at increasing lateral lengths. Our high‑specspecification well service rigs facilitate operations throughout the lifecycle of a well, including (i) well completion support,services, such as milling out composite plugs used duringafter the hydraulic fracturing;fracturing process and the installation of downhole production equipment; (ii) workover, including retrieval and replacement of existing production tubing; (iii) well maintenance, including replacement of downhole artificial lift components; and (iv) decommissioning, such as plugging and abandonment operations. The Company also provides Completion and Other Services, which provides services necessary to bring and maintain a well on production and primarily includes (i) wireline perforating and pumpdown services and (ii) snubbing services often utilized in conjunction with our high-spec rigs to convey equipment in and out of a well during completion and workover activities. The Company provides rental equipment, including well control packages, hydraulic catwalks and other equipment that are often deployed with itsour well service rigs. In addition to its core well service rig operations, the Company offers a suite of complementary services, including wireline, snubbing, well testing, fluid management and well service-related equipment rentals. In addition, the Company owns and operates a fleet of proprietary, modular natural gas processing equipment that processes rich natural gas streams at the wellhead or central gathering points. The Company has operations in most of the active oil and natural gas basins in the United States, including the Permian Basin, the Denver‑Julesburg Basin, the Bakken Shale, the Eagle Ford Shale, the Haynesville Shale, the Gulf Coast and the South Central Oklahoma Oil Province (“SCOOP”) and Sooner Trend Anadarko Basin Canadian and Kingfisher counties (“STACK”) plays.
Note 2 — Summary of Significant Accounting Policies
Basis of Presentation
The consolidated balance sheet as of December 31, 20172018 has been derived from audited financial statements and the unaudited condensed consolidated financial statements have been prepared in accordance with generally accepted accounting principles in the United States (“US GAAP”) for interim financial information and the Securities and Exchange Commission’s (the “SEC”) instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly certain notes and other information have been condensed or omitted. The unaudited condensed consolidated financial statements reflect all normal and recurring adjustments that are, in the opinion of management, necessary for the fair presentation of the results of operations for the interim periods. These interim financial statements, should be read in conjunction with the consolidated financial statements and related notes for the years ended December 31, 20172018 and 2016,2017, included in the Annual Report filed on Form 10-K for the yearyears ended December 31, 2018 and 2017 (the “Annual Report”). Interim results for the periods presented may not be indicative of results that will be realized for future periods.
Financial statements for periods

The Company has made certain reclassifications to our prior period operating revenue, cost of sales and general and administrative amounts due to the Offeringchange in reportable segments whereby our High Specification Rig and Completion and Other Services segments were bifurcated from our legacy Well Services segment as a result of our fourth quarter 2018 operating segment changes. None of these reclassifications have an impact on August 16, 2017, represent the combinedour condensed consolidated operations results, cash flows or financial statementsposition.
The Company has made certain reclassifications to our prior period Additional Paid-In Capital and Accumulated Deficit amounts. None of the Predecessor. Financial statements for periods subsequent to the Offering reflect thethese reclassifications have an impact on our condensed consolidated operations results, cash flows or financial statements of the Company.position.
Significant Accounting Policies
The Company’s significant accounting policies are disclosed in Note 2 — Summary of Significant Accounting Policies of the Annual Report. There have been no changes in such policies or the application of such policies during the three and ninesix months ended SeptemberJune 30, 20182019, except as discussed in Note 37 — Revenue from Contracts with Customers.Leases and below.
Use of Estimates
The preparation of financial statements in conformity with US GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the reporting period. Management uses historical and other pertinent information to determine these estimates. Actual results could differ from such estimates. Areas where critical accounting estimates are made by management include:
Depreciation and amortization of property, plant and equipment and intangible assets;
Impairment of property, plant and equipment, goodwill and intangible assets;
Allowance for doubtful accounts;
Fair value of assets acquired and liabilities assumed in an acquisition; and


Equity‑based compensation.
Emerging Growth Company status
The Company is an “emerging growth company” as defined in the Jumpstart Our Business Startups Act of 2012 (the “JOBS Act”). The Company will remain an emerging growth company until the earlier of (1) the last day of its fiscal year (a) following the fifth anniversary of the completion of the Offering, (b) in which its total annual gross revenue is at least $1.07 billion, or (c) in which the Company is deemed to be a large accelerated filer, which means the market value of the Company’s common stock that is held by non-affiliates exceeds $700.0 million as of the last business day of its most recently completed second fiscal quarter, andor (2) the date on which the Company has issued more than $1.0 billion in non-convertible debt securities during the prior three-year period. An emerging growth company may take advantage of specified reduced reporting and other burdens that are otherwise applicable generally to public companies. The Company has irrevocably opted out of the extended transition period and, as a result, the Company will adopt new or revised accounting standards on the relevant dates on which adoption of such standards is required for other public companies.
New Accounting Pronouncements
Recently Adopted Accounting Standards
In February 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2016‑2, 02, Leases, amending the current accounting for leases. Under the new provisions, all lessees will report a right‑of‑use asset and a liability for the obligation to make payments for all leases with the exception of those leases with a term of 12 months or less. All other leases will fall into one of two categories: (i) a financing lease or (ii) an operating lease. Lessor accounting remains substantially unchanged with the exception that no leases entered into after the effective date will be classified as leveraged leases. For sale leaseback transactions,
Effective January 1, 2019, the Company has adopted ASU 2016-02 and elected the following practical expedients and accounting policy elections for recognition, measurement and presentation:
The optional transition method, therefore will not adjust comparative period financial information or make the new required lease disclosures for periods prior to the effective date;
the package of practical expedients to not reassess prior conclusions related to (i) contracts containing leases, (ii) lease classification and (iii) initial direct costs;
to make the accounting policy election for short-term leases, or leases with terms of 12 months or less, therefore the lease payments will be recorded as an expense on a sale will only bestraight line basis over the lease term; and


to combine lease and non-lease components.
The Company did not apply the practical expedient to utilize hind-sight in applying the standard. ROU assets represent our right to use an underlying asset for the lease term and lease liabilities represent our obligation to make lease payments arising from the lease, discounted at our annual incremental borrowing rate (“IBR”). ROU assets and liabilities are recognized ifat the criteriacommencement date based on the present value of lease payments over the lease term. Variable lease payments are excluded from the ROU asset and lease liabilities and are recognized in the new revenue recognition standardperiod in which the obligation for those payments are met. ASU 2016‑2 is effective for fiscal years beginning after December 15, 2018, including interim periods withinincurred. For certain leases, where variable lease payments are incurred and relate primarily to common area maintenance, in substance fixed payments are included in the ROU asset and lease liability. For those leases that reporting period, using a modified retrospective approach.do not provide an implicit rate, we use our IBR based on the information available at the lease commencement date in determining the present value of lease payments. ROU assets also include any lease payments made and exclude lease incentives. Lease terms do not include options to extend or terminate the lease, as management does not consider them reasonably certain to exercise. The Company will applyhas a related party lease, which is included within the new lease standard asROU asset and liability. Please see Note 14 — Related Party Transactions of the Annual Report for further discussion of the Company’s related parties.
As of January 1, 2019, the Company recognized an operating lease right-of-use asset and recognize a cumulative-effect adjustment to retained earnings. We have identified all leases that will have an impactcorresponding liability of $8.3 million on our condensed consolidated financial statements and related disclosures. The Company is evaluating the effect of this ASU, including any newly issued guidance, on the condensed consolidated financial statements and related disclosures.
In June 2016, the FASB issued ASU 2016‑13, Financial Instruments—Credit Losses. The amendments in ASU 2016‑13 require the measurement of all expected credit lossesBalance Sheet. See Note 7 — Leases, for financial assets held at the reporting date based on historical experience, current conditions and reasonable and supportable forecasts. In addition, ASU 2016‑13 amends the accounting for credit losses on available‑for‑sale debt securities and purchased financial assets with credit deterioration. The amendment is effective for public entities for annual reporting periods beginning after December 15, 2019, however early application is permitted for reporting periods beginning after December 15, 2018. The Company does not expect this to have a material impact on its consolidated financial statements.
In August 2016, the FASB issued ASU 2016‑15, Statement of Cash Flows (Topic 230), Classification of Certain Cash Receipts and Cash Payments. ASU 2016‑15 reduces diversity in practice in how certain transactions are classified in the statement of cash flows. The guidance addresses specific cash flow issues for which current GAAP is either unclear or does not include specific guidance. ASU 2016‑15 is effective for annual and interim periods beginning after December 15, 2017. The Company adopted the new guidance on the effective date of January 1, 2018 and noted no material impact on the consolidated financial statements of cash flows.
In November 2016, the FASB issued ASU 2016-18, Statement of Cash Flows (Topic 230), Restricted Cash. ASU 2016-18 requires restricted cash and restricted cash equivalents be included with cash and cash equivalents when reconciling the beginning and end of period total amounts presented on the statement of cash flows. The Company adopted the new guidance on the effective date of January 1, 2018 and noted no material impact on the consolidated financial statements of cash flows.
In January 2017, the FASB issued ASU 2017‑4, Intangibles—Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment. ASU 2017‑4 eliminates the requirement to calculate the implied fair value of goodwill to measure a goodwill impairment charge. Instead, entities will record an impairment charge based on the excess of a reporting unit’s carrying amount over its fair value. The ASU is effective for annual and interim impairment tests performed in periods beginning after December 15, 2019. The Company adopted this guidance for its current annual and interim goodwill impairment testing as of January 1, 2018. The ASU impacted how the Company tests goodwill for impairment, as it eliminates the second stepfurther details of the goodwill impairment test, thus effectively calculating impairment loss based on the difference between the carrying valueCompany’s operating and estimated fair value of the reporting units. financing leases.
Recently Issued Accounting Standards
With the exception of the updated standardsstandard above, there have been no new accounting pronouncements not yet effective that have significance, or potential significance, to the Company'sCompany’s condensed consolidated financial statements.



Note 3 — Revenue from Contracts with Customers
Effective January 1, 2018, the Company adopted Accounting Standards Codification (“ASC”) Revenue from Contracts with Customers (“ASC 606”), using the modified retrospective method. This standard applies to all contracts with customers, except for contracts that are within the scope of other standards, such as leases, insurance, collaborative arrangements and financial instruments. Under ASC 606, an entity recognizes revenue when it transfers control of the promised goods or services to its customer, in an amount that reflects the consideration which the entity expects to receive in exchange for those goods or services. If control transfers to the customer over time, an entity selects a method to measure progress that is consistent with the objective of depicting its performance. The provisions of ASC 606 were applied to contracts not completed at January 1, 2018. There was no impact upon adoption of ASC 606. As a result, no disclosure of the impact for each financial statement line items is applicable.
In determining the appropriate amount of revenue to be recognized as the Company fulfills the obligations under its contracts with customers, the following steps must be performed at contract inception: (i) identification of the promised goods or services in the contract; (ii) determination of whether the promised goods or services are performance obligations, including whether they are distinct in the context of the contract; (iii) measurement of the transaction price, including the constraint on variable consideration; (iv) allocation of the transaction price to the performance obligations and (v) recognition of revenue when (or as) the Company satisfies each performance obligation.
The Company conducts its business through two segments: Well Services and Processing Solutions. The Well Services segment consists primarily of maintenance, workover, completion and plugging and abandonment services. The Processing Solutions segment consists primarily of equipment rentals and services related to operations, maintenance and mobilization. The services of each segment are based on mutually agreed upon pricing with the customer prior to the services being performed, and given the nature of the services, do not include any warranty and right of return. Pricing for these services are by the hour or by the day, when services are performed and are based on the nature of the specific job, with consideration for the extent of equipment, labor, and consumables needed for the job. Accordingly, the hourly and daily pricing is considered to be variable consideration. Pricing for equipment rentals is based on fixed monthly service fees. For more information on the Company's segments, see Note 17 — Segment Reporting.
We satisfy our performance obligation over time as the services are performed. The Company believes the output method is a reasonable measure of progress for the satisfaction of our performance obligations, which are satisfied over time, as it provides a faithful depiction of (1) our performance toward complete satisfaction of the performance obligation under the contract and (2) the value transferred to the customer of the services performed under the contract. The Company has elected the right to invoice practical expedient for recognizing revenue. The Company invoices customers upon completion of the specified services and collection generally occurs within the payment terms agreed with customers. Accordingly, there is no financing component to our arrangements with customers.
Taxes assessed on well services and processing solutions revenue transactions are presented on a net basis included within the consolidated statements of operations and therefore are excluded from revenues.
Disaggregated Revenue
The following table summarizes our disaggregated revenues for the three and nine months ended September 30, 2018 and 2017 (in millions):
  Three Months Ended September 30, Nine Months Ended September 30,
  2018 2017 2018 2017
Well Services revenue        
Workover rigs revenue $40.8
 $31.6
 $119.7
 $77.1
Other Well Services revenue 37.3
 7.4
 87.2
 20.8
Total Well Services revenue 78.1
 39.0
 206.9
 97.9
Processing Solutions revenue 4.0
 2.1
 10.9
 5.9
Total Revenue $82.1
 $41.1
 $217.8
 $103.8
Contract Balances
Contract assets representing the Company’s rights to consideration for work completed but not billed amounted to $4.2 million as of September 30, 2018 and $6.0 million as of December 31, 2017. Substantially all of the unbilled trade receivables as of December 31, 2017 were invoiced during the nine months ended September 30, 2018.
The Company does not have any contract liabilities included in the consolidated balance sheet as of September 30, 2018 and December 31, 2017.


Note 4 — Acquisitions
ESCO Acquisition
On August 16, 2017, Ranger LLC acquired 49 high-spec well service rigs, certain ancillary equipment and certain of its liabilities (the “ESCO Acquisition”). In connection with the closing of the Offering on August 16, 2017, the Company closed on the ESCO Acquisition for total consideration of $59.7 million, consisting of $47.7 million in cash, $7.0 million in secured seller notes and $5.0 million in shares of Ranger’s Class A Common Stock based on the Offering price of $14.50 per share.
The ESCO Acquisition assets were primarily engaged in the completion, repair and workover of oil and gas wells for its customers. The ESCO Acquisition is being accounted for as a business combination. Goodwill was recorded in conjunction with the ESCO Acquisition as the total purchase consideration exceeded the approximated fair value of assets acquired and liabilities assumed.
The following information below represents the purchase price allocation related to the ESCO Acquisition (in millions):
Purchase price  
Cash $47.7
Seller's notes 7.0
Equity issued 5.0
Total purchase price $59.7
Purchase price allocation  
Accounts receivable $6.6
Property, plant and equipment 45.9
Intangible assets 2.2
Other assets 0.3
Total assets acquired 55.0
Accounts payable (0.5)
Accrued expenses (2.2)
Total liabilities assumed (2.7)
Goodwill 7.4
Allocated purchase price $59.7
The following is supplemental pro-forma revenue, operating loss, and net loss had the ESCO Acquisition occurred as of January 1, 2017. (in millions):
  Nine Months Ended September 30,
  2018 2017
Supplemental Pro Forma:    
Revenue $217.8
 $126.5
Operating Loss (5.4) (17.2)
Net Loss $(7.5) $(23.7)
The supplemental pro forma revenue, operating loss and net loss are presented for informational purposes only and may not necessarily reflect the future results of operations of the Company or what the results of operations would have been had the Company owned and operated the ESCO Acquisition assets since January 1, 2017.  
The Company reported revenue during the three and nine months ended September 30, 2018 that included $9.9 million and $26.9 million, respectively, generated from the assets acquired in connection with the ESCO Acquisition.
MVCI Acquisition
On January 31, 2018, the Company closed on the acquisition of MVCI Energy Services (“MVCI Acquisition”) for a total consideration of $4.0 million in cash. The MVCI Acquisition assets were primarily engaged in well testing services for its customers. The MVCI Acquisition is being accounted for as a business combination. The Company evaluated its purchase allocation and has reported $4.0 million on its consolidated balance sheets as property, plant and equipment. The pro forma results of operations for the MVCI Acquisition is not presented because the pro forma effects, individually and in the aggregate, are not material to the Company’s consolidated results of operations.



Note 5 — Assets Held for Sale
The Company has decided to market and sell non‑core rental fleet assets. The units consist of wedge units, which are classified as held for sale, as they are specifically identified and management has a plan for their sale, in their present condition, within the next year. The wedge units are recorded on the consolidated financial statement with a balance of $0.6 million as of September 30, 2018 and are classified as held for sale. The available for sale assets are recorded at the units’ carrying amount, which approximates fair value less costs to sell, and are no longer depreciated.
Note 64 — Property, Plant and Equipment, Net
Property, plant and equipment include the following (in millions):
 
Estimated
Useful Life
(years)
 September 30, 2018 December 31, 2017 Estimated Useful Life (years) June 30, 2019 December 31, 2018
Machinery and equipment 5 - 30 $3.7
 $3.7
 5 - 30 $42.3
 $42.0
Vehicles 3 - 5 9.8
 2.6
 3 - 5 18.8
 17.9
Mechanical refrigeration units 30 19.0
 17.1
 30 21.8
 20.9
Natural Gas Liquid ("NGL") storage tanks 15 4.6
 4.3
Workover rigs and complimentary equipment 5 - 20 220.1
 174.9
Natural gas liquid storage tanks 15 5.9
 5.9
High specification rigs 5 - 20 178.4
 175.7
Other property, plant and equipment 3 - 30 17.6
 12.0
 3 - 30 16.1
 12.7
Property, plant and equipment 274.8
 214.6
 283.3
 275.1
Less: accumulated depreciation (44.1) (25.4) (68.7) (52.5)
Construction in progress 13.1
 7.2
Property, plant and equipment, net $230.7
 $189.2
 $227.7
 $229.8
Depreciation expense was $20.0$8.2 million and $11.3 million for the nine months ended September 30, 2018 and 2017, respectively. Depreciation expense was $7.4 million and $3.9$6.8 million for the three months ended SeptemberJune 30, 2019 and 2018, respectively, and 2017,$16.5 million and $12.7 million for the six months ended June 30, 2019 and 2018, respectively.


Note 75 — Goodwill and Intangible Assets
Goodwill was $9.0 million as ofDuring the year ended December 31, 2017. During the nine months ended September 30, 2018, the Company identified a triggering event as it relates to goodwill as a result ofnoted a sustained decrease in the stock price, which was an indication that the fair value of the Company.goodwill could have fallen below its carrying amount. As a result, the Company performed a quantitative impairment test which yielded an impairment charge and recorded an impairmentdetermined the goodwill was impaired. The Company estimated the implied fair value of the goodwill using a variety of $9.0 million. As of September 30, 2018 there is no goodwill onvaluation methods, including the Company's consolidated balance sheet.
income and market approaches. During the nine monthsyear ended September 30,December 31, 2018, the Company had nonrecurringrecognized an impairment loss of $9.0 million associated with the remaining balance of our goodwill. The estimate of fair value measurements related to the impairment of goodwill. The fair values were determined throughrequired the use of significant unobservable inputs, representative of a blended market and income approach, which represent Level 3 measurements within the fair value hierarchy.measurement.
Definite lived intangible assets are comprised of the following (in millions):
 Estimated
Useful Life
(years)		 September 30, 2018 December 31, 2017 Estimated Useful Life (years) June 30, 2019 December 31, 2018
Tradenames 3 $0.1
 $0.1
 3 $0.1
 $0.1
Customer relationships 10-18 11.4
 11.4
 10-18 11.4
 11.4
Less: accumulated amortization (1.3) (0.7) (1.8) (1.5)
Intangible assets, net $10.2
 $10.8
 $9.7
 $10.0
Amortization expense was $0.6 million and $0.4 million for the nine months ended September 30, 2018 and 2017, respectively. Amortization expense was $0.1$0.2 million and $0.2 million for the three months ended SeptemberJune 30, 2019 and 2018, respectively, and 2017,$0.3 million and $0.4 million for the six months ended June 30, 2019 and 2018, respectively. Amortization expense for the future periods is expected to be as follows (in millions):
Twelve months ending September 30, Amount
2019 $0.8
2020 0.7
2021 0.7
2022 0.7
2023 0.7
Thereafter 6.6
  $10.2
Due to the triggering event and goodwill impairment charged during the nine months ended September 30, 2018, the Company assessed whether the long-lived assets, which consist of property, plant and equipment and intangible assets, were impaired by comparing the carrying value of its long-lived assets to the estimated future undiscounted cash flows of their reporting units and concluded they were not impaired.
For the twelve months ending June 30, Amount
2020 $0.7
2021 0.7
2022 0.7
2023 0.7
2024 0.8
Thereafter 6.1
  $9.7
Note 86 — Accrued Expenses
Accrued expenses include the following (in millions):
 September 30, 2018 December 31, 2017 June 30, 2019 December 31, 2018
Accrued payables $11.9
 $4.8
 $7.1
 $5.6
Accrued payroll 10.3
 2.9
Accrued compensation 10.2
 6.2
Accrued taxes 3.5
 1.4
 2.0
 2.9
Accrued insurance 1.4
 2.5
 0.5
 3.8
Accrued expenses $27.1
 $11.6
 $19.8
 $18.5
Note 97 — Capital Leases
Operating Leases
The Company has operating leases, primarily for real estate and equipment, with terms that vary from less than 12 months, included in Short-term leases costs in the table below, to eight years, included in Operating lease costs in the table below. The operating leases are included in Operating lease right-of-use assets, Other current liabilities and Operating lease right-of-use obligations in our Condensed Consolidated Balance Sheet.


Lease costs and other information related to operating leases for the three and six months ended June 30, 2019, is as follows (in millions):
  Three Months Ended Six Months Ended
  June 30, 2019
Short-term lease costs $1.1
 $3.3
Operating lease cost $0.6
 $1.3
Operating cash flows from operating leases $(0.6) $(1.4)
     
Weighted average remaining lease term   5.7 years
Weighted average discount rate   9.35%
Aggregate future minimum lease payments under operating leases are as follows (in millions):
For the twelve months ending June 30, Total
2020 $2.7
2021 1.4
2022 0.8
2023 0.7
2024 0.7
Thereafter 2.6
Total future minimum lease payments 8.9
Less: amount representing interest (2.2)
Present value of future minimum lease payments 6.7
Less: current portion of operating lease obligations (2.1)
Long-term portion of operating lease obligations $4.6
Aggregate future minimum rental payments as of December 31, 2018, were as follows (in millions):
For the year ending December 31, Total
2019 $2.9
2020 2.3
2021 0.9
2022 0.7
2023 0.7
Thereafter 3.0
Total future minimum lease payments $10.5
Finance Leases
The Company leases certain assets, primarily automobiles, under capitalfinance leases which expire at various dates through 2021.are generally three to five years. The assets and liabilities under capitalfinance leases are recorded at the lower of present value of the minimum lease payments or the fair value of the assets. The assets are amortized over the shorter of the estimated useful lives or over the lease term. Amortization expense of assets under capitalThe finance leases was $2.5 millionare included in Property and $1.2 million for the nine months ended September 30, 2018equipment, net, Finance lease obligations, current portion and 2017, respectively. Amortization expense of assets under capitalFinance lease obligations in our Condensed Consolidated Balance Sheet.
Lease costs and other information related to finance leases was $1.4 million and $0.4 million for the three and six months ended SeptemberJune 30, 2018 and 2017, respectively.2019, is as follows (in millions):
  Three Months Ended Six Months Ended
  June 30, 2019
Amortization of finance leases $1.2
 $2.5
Interest on lease liabilities $0.2
 $0.4
Financing cash flows from finance leases $(1.2) $(2.2)
     
Weighted average remaining lease term 
 1.8 years
Weighted average discount rate 
 4.5%


Aggregate future minimum lease payments under capitalfinance leases are as follows (in millions):
As of September 30, Total
2018 $1.1
2019 4.3
For the twelve months ending June 30, Total
2020 3.9
 $5.1
2021 1.4
 3.7
2022 1.4
2023 0.2
Thereafter 0.4
 —
Total future minimum lease payments 11.1
 10.4
Less: amount representing interest (0.7) (0.8)
Present value of future minimum lease payments 10.4
 9.6
Less: current portion of capital lease obligations (3.9)
Total capital lease obligations, less current portion $6.5
Less: current portion of finance lease obligations (4.8)
Long-term portion of finance lease obligations $4.8
Aggregate future minimum rental payments as of December 31, 2018, were as follows (in millions):
For the year ending December 31, Total
2019 $5.0
2020 4.6
2021 2.1
2022 0.2
2023 0.1
Thereafter —
Total future minimum lease payments 12.0
Less: amount representing interest (1.0)
Present value of future minimum lease payments 11.0
Less: current portion of capital lease obligations (4.4)
Total capital lease obligations, less current portion $6.6


Note 108 — Debt
The aggregate carrying amounts, net of issuance costs, of the Company'sCompany’s debt consists of the following (in millions):
  September 30, 2018 December 31, 2017
Long-term debt $20.4
 $—
Credit Facility 17.9
 0.1
Other debt 5.8
 7.0
Total debt 44.1
 7.1
Current portion of long-term debt (11.3) (1.3)
Long term-debt $32.8
 $5.8
  June 30, 2019 December 31, 2018
ESCO Notes Payable due February 2019 $5.8
 $5.8
Wells Fargo Credit Facility due August 2022 25.8
 17.9
Encina Master Financing Agreement due June 2023 32.0
 36.8
Total Debt 63.6
 60.5
Current portion of long-term debt (15.8) (15.8)
Long term-debt, net $47.8
 $44.7
ESCO Notes Payable
In connection with the OfferingCompany’s initial public offering (the “Offering”) and the ESCO Acquisition, both of which occurred on August 16, 2017, the Company issued $7.0 million of seller’s notes as partial consideration for the ESCO Acquisition. These notes include a note for $1.2 million, which was paid in August 2018 and a note for $5.8 million due in February 2019. Both of these notes bear interest at 5.0% payable quarterly until their respective maturity dates.
During the year ended December 31, 2018, the Company provided notice to ESCO Leasing, LLC that the Company sought to be indemnified for breach of contract. The Company exercised its right to stop payments of the remaining principal balance of $5.8 million on the Seller’s Notes and any unpaid interest, pending resolution of certain indemnification claims.
Credit Facility
On August 16, 2017, in connection with the Offering, Ranger entered into a $50.0 million senior revolving credit facility (the “Credit Facility”) by and among certain of Ranger’s subsidiaries, as borrowers, each of the lenders party thereto and Wells Fargo Bank, N.A., as administrative agent (the “Administrative Agent”). The Credit Facility is subject to a borrowing base that is calculated based upon a percentage of the value of the Company'sCompany’s eligible accounts receivable less certain reserves.


The Credit Facility permits extensions of credit up to the lesser of $50.0 million and a borrowing base that is determined by calculating the amount equal to the sum of (i) 85% of the Eligible Accounts (as defined in the Credit Facility), less the amount, if any, of the Dilution Reserve (as defined in the Credit Facility), minus (ii) the aggregate amount of Reserves (as defined in the Credit Facility), if any, established by the Administrative Agent from time to time pursuant to the Credit Facility. The borrowing base is calculated on a monthly basis pursuant to a borrowing base certificate delivered by the Company to the Administrative Agent.
Borrowings under the Credit Facility bear interest, at the Company'sCompany’s election, at either the (a) one-, two-, three- or six-month LIBOR or (b) the greatest of (i) the federal funds rate plus ½%, (ii) the one-month LIBOR plus 1% and (iii) the Administrative Agent’s prime rate (the “Base Rate”), in each case plus an applicable margin, and interest shall be payable monthly in arrears. The applicable margin for LIBOR loans ranges from 1.50% to 2.00% and the applicable margin for Base Rate loans ranges from 0.50% to 1.00%, in each case, depending on the Company'sCompany’s average excess availability under the Credit Facility. The applicable margin for LIBOR loans is 1.50%was 1.75% and the applicable margin for Base Rate loans are 0.50%were 0.75% as of SeptemberJune 30, 2018.2019. During the continuance of a bankruptcy event of default, automatically and during the continuance of any other default, upon the Administrative Agent’s or the required lenders’ election, all outstanding amounts under the Credit Facility bears interest at 2.00% plus the otherwise applicable interest rate. The Credit Facility is scheduled to mature on August 16, 2022.2022 and has a weighted average interest rate of 4.7% as of June 30, 2019.
In addition, the Credit Facility restricts the Company’s ability to make distributions on, or redeem or repurchase, its equity interests, except for certain distributions, including distributions of cash so long as, both at the time of the distribution and after giving effect to the distribution, no default exists under the Credit Facility and either (a) excess availability at all times during the preceding 90 consecutive days, on a pro forma basis and after giving effect to such distribution, is not less than the greater of (1) 22.5% of the lesser of (A) the maximum revolver amount and (B) the then-effective borrowing base and (2) $10.0 million or (b) if the fixed charge coverage ratio is at least 1.0x on a pro forma basis, excess availability at all times during the preceding 90 consecutive days, on a pro forma basis and after giving effect to such distribution, is not less than the greater of (1) 17.5% of the lesser of (A) the maximum revolver amount and (B) the then-effective borrowing base and (2) $7.0 million. If the foregoing threshold under clause (b) is met, the Company may not make such distributions (but may make certain other distributions, including under clause (a) above) prior to the earlier of the date that is (a) 12 months from closing or (b) the date that the Company’s fixed charge coverage ratio is at least 1.0x for two consecutive quarters. The Credit Facility generally permits the Company to make distributions required under the Tax Receivable Agreement (‘‘TRA’’), but a ‘‘Change of Control’’ under the TRA constitutes an event of default under the Credit Facility, and the Credit Facility does not permit the Company to make payments under the TRA upon acceleration of its obligations thereunder unless no event of default exists or would result therefrom and the Company has been in compliance with the fixed charge coverage ratio for the most recent 12-month period on a pro forma basis. The Credit Facility also requires the Company to maintain a fixed charge coverage ratio of at least 1.0x if the Company’s liquidity is less than $10.0 million until the Company’s liquidity is at least $10.0 million for 30 consecutive days. The Company is not to be subject to a fixed charge coverage ratio if it has no drawings under the Credit Facility and has at least $20.0 million of qualified cash.


The Credit Facility contains events of default customary for facilities of this nature, including, but not limited, to:
events of default resulting from the Company’s failure or the failure of any guarantors to comply with covenants and financial ratios;
the occurrence of a change of control;
the institution of insolvency or similar proceedings against the Company or any guarantor; and
the occurrence of a default under any other material indebtedness the Company 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 Credit Facility, the lenders are able to declare any outstanding principal of the Credit Facility debt, together with accrued and unpaid interest, to be immediately due and payable and exercise other remedies.
As of SeptemberJune 30, 2018,2019, the Company has borrowed $18.5$26.3 million under the Credit Facility. The Company has a borrowing capacity of approximately $40.2$40.3 million under the Credit Facility, with approximately $21.7$14.0 million available as of SeptemberJune 30, 2018.2019. The Company was in compliance with the Credit Facility covenants as of SeptemberJune 30, 2018.2019.
The Company capitalized fees of $0.7 million associated with the Credit Facility, which are included in the unaudited interim condensed consolidated balance sheets as a discount to the Credit Facility, and will be amortized through maturity. Unamortized debt issuance costs as of SeptemberJune 30, 20182019 approximated $0.6$0.5 million.


Encina Master Financing and Security Agreement (“Financing Agreement”)
On June 22, 2018, the Company entered into a Master Financing and Security Agreement ("Financing Agreement") with Encina Equipment Finance SPV, LLC (the “Lender”). The amount available to be provided by the Lender to the Company under the Financing Agreement was contemplated to be not less than $35.0 million, and not to exceed $40.0 million. The first financing was required to be in an amount up to $22.0 million, or $21.3 million, net of expenses, which was used by the Company to acquire certain capital equipment. Subsequent financings could be made, as agreed byto the first financing, the Company and Lender. Amountsborrowed an additional $18.0 million, or $17.8 million, net of expenses, under the Financing Agreement. We utilized the additional net proceeds to acquire certain capital equipment. The Financing Agreement is secured by a lien on certain high specification rig assets. At June 30, 2019, the aggregate principal balance outstanding was $32.7 million under the Financing Agreement are payable ratably over 48 months through the maturitywith a weighted average interest rate of July 2022. 10.5%.
Borrowings under the Financing Agreement bear interest at a rate per annum equal to the sum of 8.0% plus the London Interbank Offered Rate ("LIBOR"(“LIBOR”), which was 2.2%2.4% as of SeptemberJune 30, 2018.2019. The Financing Agreement requires that the Company maintain leverage ratios of 5.002.50 to 1.00 as of SeptemberJune 30, 2018, 3.50 to 1.00 as of December 31, 20182019 and 2.50 to 1.00 for periods thereafter. The Company was in compliance with the covenants under the Financing Agreement as of SeptemberJune 30, 2018.
As of September 30, 2018, the principal balance outstanding was $21.1 million under the Financing Agreement and future payments are as follows (in millions):
Twelve months ending September 30, Total
2019 $5.5
2020 5.5
2021 5.5
2022 4.6
Total 21.1
2019.
The Company capitalized fees of $0.7$0.9 million associated with the Financing Agreement, which are included on the unaudited interim condensed consolidated balance sheets as a discount to the long term debt, and will be amortized through maturity. Unamortized debt issuance costs as of SeptemberJune 30, 20182019 approximated $0.7 million.
Scheduled Maturities
As of June 30, 2019, aggregate principal repayments of total debt for the next five years are as follows (in millions):
For the twelve months ending June 30, Total
2020 $15.8
2021 10.0
2022 36.3
2023 2.7
Total $64.8
Note 11 9— Risk ConcentrationsEquity
Customer Concentrations Equity-Based Compensation
ForTime-Based Units
During the ninesix months ended SeptemberJune 30, 2018, one customer, EOG Resources, accounted for approximately 22% of the Company’s total Well Services segment revenues. For the three months ended September 30, 2018, two customers, EOG Resources2019 and Centennial Resource Development, Inc., accounted for approximately 20% and 11% of the Company’s total Well Services segment revenues, respectively. At September 30, 2018, approximately 27% of the accounts receivable balance was due from these customers.
For the nine months ended September 30, 2017, two customers, EOG Resources and PDC Energy, accounted for approximately 13% and 19%, of the Company’s total Well Services segment revenues, respectively. For the three months ended September 30, 2017, two customers, EOG Resources and PDC Energy, accounted for approximately 12% and 12%, of the Company’s total Well Services segment revenues, respectively. At September 30, 2017, approximately 22% of the accounts receivable balance was due from these customers.


Note 12 — Equity Based Compensation and Profit Interest Awards
Long-term Incentive Plan
On August 10, 2017, the board of directors adopted the Ranger Energy Services, Inc. 2017 Long-term Incentive Plan (“LTIP”) for the employees, consultants and the directors of the Company and its affiliates who perform services for the Company. The LTIP provides for potential grants of: (i) incentive stock options qualified as such under U.S. federal income tax laws; (ii) nonstatutory stock options that do not qualify as incentive stock options; (iii) stock appreciation rights; (iv) restricted stock awards; (v) restricted stock units; (vi) bonus stock; (vii) performance awards; (viii) dividend equivalents; (ix) other stock-based awards; (x) cash awards and (xi) substitute awards. Subject to adjustment in accordance with the terms of the LTIP, 1,250,000 shares of Class A Common Stock have been reserved for issuance pursuant to awards under the LTIP. Class A Common Stock withheld to satisfy exercise prices or tax withholding obligations will be available for delivery pursuant to other awards. The LTIP will be administered by the board of directors or an alternative committee appointed by the board of directors. As of September 30, 2018 there have been 563,002were 495,750 and 498,302 restricted shares granted, under the LTIP.
Time Based Restricted Stock
During the ninerespectively. The aggregate value of awards granted during six months ended SeptemberJune 30, 2018 there were 553,002 restricted shares issued with a total grant date fair value of $4.6 million. Stock-based compensation expense recorded for restricted shares for the nine months ended September 30,2019 and 2018 was $0.9 million. There$3.9 million and $4.1 million, respectively. As of June 30, 2019, there was approximately $3.3an aggregate $5.6 million of unrecognized compensation expense related to outstanding restricted shares as of September 30, 2018,issued which is expected to be recognized over a weighted average period of 2.72.2 years.
The following table summarizes the changes in the restricted shares outstanding for the nine months ended September 30, 2018:
  Shares 
Weighted Average
Grant Date
Fair Value
 
Weighted Average
Remaining
Vesting Period
Unvested at December 31, 2017 10,000
 $9.43
 2.4 years
Granted 553,002
 8.27
 2.4 years
Forfeited (34,806) 
 
Vested (31,779) 
 
Unvested at September 30, 2018 496,417
 $8.29
 2.6 years
Market Based Performance Restricted Stock Units
During the ninesix months ended SeptemberJune 30, 2018,2019, the Company granted 39,715105,920 target shares of market based performance restricted stock units at a relative and absolute grant date fair value of approximately $11.96 per share and $9.50 per share, respectively, to certain employees. The market based performance restricted stock units cliff vest on March 21, 2022. As defined in the LTIP, the performance criteria applicable to the performance awards is measured at a relative and absolute shareholder return, which measures the Company’s total shareholder return as compared to the total shareholder return of the defined peer group. As of June 30, 2019, there was approximately $1.0 million of unrecognized compensation cost related to shares of market based performance restricted stock units which is expected to be recognized over a weighted average period of 2.5 years.
During the three and six months ended June 30, 2018, the Company granted 79,430 target shares of market based performance restricted stock units at a relative and absolute grant date fair value of approximately $8.59 per share and $4.38 per share, respectively, to certain employees. The market based performance restricted stock units cliff vest on December 31, 2020. TheAs defined in the LTIP, the performance criteria applicable to suchthe performance awards is measured at a relative totaland absolute shareholder return, which measures the Company'sCompany’s total shareholder return as compared to the total shareholder return of the defined peer group identified by the board of directors.group. As of SeptemberJune 30, 2018,2019, there was $0.3 million of unrecognized compensation cost related to shares of market based performance restricted stock units which is expected to be recognized over a weighted average period of 2.31.5 years.
During

Share Issuance to Related Party
In connection with the nineMaster Reorganization Agreement, an aggregate of $3.0 million (included within other current liabilities on the accompanying consolidated balance sheet as of December 31, 2018) was settled by the Company and CSL Energy Holdings I, LLC and CSL Energy Holdings II, LLC during the three and six months ended SeptemberJune 30, 2018,2019. At the Company’s discretion the liability was settled with the issuance of 206,897 Class A Common Stock. Refer to Note 1 — Organization and Business Operations for further details.
Share Repurchase Program
In June 2019, the Board of Directors approved a share repurchase program, authorizing the Company granted 39,715 target shares of market based performance restricted stock units at a grant date fair value of $4.38 per share to certain employees. The market based performance restricted stock units cliff vest on December 31, 2020. The performance criteria applicablepurchase up to such awards is absolute total shareholder return, which measures the Company's total shareholder return as compared to the value10% of the Company'soutstanding Class A Common Stock atheld by non-affiliates, not to exceed 580,000 shares or $5.0 million in aggregate value. Share repurchases may take place from time to time on the timeopen market or through privately negotiated transactions. The duration of the Offeringshare repurchase program is 12 months and may be accelerated, suspended or discontinued at any time without notice. During the three months ended June 30, 2019, the Company did not repurchase any Class A Common Stock. Refer to “Part II, Item 2. Unregistered Sales of $14.50. AsSecurities” for further information.
Note 10 — Risk Concentrations
Customer Concentrations 
For the three months ended June 30, 2019, two customers, EOG Resources and Concho Resources, Inc., accounted for 17% and 15%, respectively, of Septemberthe Company’s total revenue. For the six months ended June 30, 2019, two customers, EOG Resources and Concho Resources, Inc., accounted for 17% and 14%, respectively, of the Company’s total revenues. At June 30, 2019, approximately 19% of the accounts receivable balance was due from these customers.
For the three months ended June 30, 2018, there was $0.1 millionone customer, EOG Resources, accounted for approximately 23% of unrecognized compensation cost related to shares of market based performance restricted stock units which is expected to be recognized over a weighted average period of 2.3 years.
During the nineCompany’s total revenues. For the six months ended SeptemberJune 30, 2018, and 2017,one customer, EOG Resources, accounted for approximately 22%, of the Company recognized compensation expense of $0.5 million and $0.8 million, respectively, related to the Class C and Class D units issued by Ranger Holdings and Torrent Holdings. TheCompany’s total unrecognized compensation cost related to unvested awards at Septemberrevenues. At June 30, 2018, is $0.4 million and is expected to be recognized overapproximately 18% of the next 1.8 years.accounts receivable balance was due from this customer.


Note 1311 — Income Taxes
The Company is a corporation and is subject to U.S. federal income tax. The tax implications of the Offering and the Company’s concurrent corporate reorganization, and the tax impact of the Company’s status as a taxable corporation subject to U.S. federal income tax have been reflected in the accompanying condensed consolidated financial statements. The effective U.S. federal income tax rate applicable to the Company for the ninesix months ended SeptemberJune 30, 2019 and 2018 was 11.3% and 2017 was 3.6% and 0.0%7.3%, respectively. Total income tax expense for the three and nine months ended September 30, 2018 differed from amounts computed by applying the U.S. federal statutory tax rate of 21% due primarily to state taxes and changes in the valuation allowance recorded against deferred tax assets. The Company is subject to the Texas Margin Tax that requires tax payments at a maximum statutory effective rate of 0.75% on the taxable margin of each taxable entity that does business in Texas.
As a result of the Offering and subsequent reorganization, the Company recorded a deferred tax asset; however, a full valuation allowance has been recorded to reduce the Company’s net deferred tax assets to an amount that is more likely than not to be realized and is based upon the uncertainty of the realization of certain federal and state deferred tax assets related to net operating loss carryforwards and other tax attributes. The Company currently believes that it is reasonably possible to achieve a three-year cumulative level of profitability within the next 12 months, and as early as the third quarter of 2019, which would enhance the ability to conclude that is it more likely than not that the deferred tax assets would be realized and support a release of a portion or substantially all of the valuation allowance. A release of the valuation allowance would result in the recognition of an increase in deferred tax assets and an income tax benefit in the period in which the release occurs, although the exact timing and amount of the release is subject to change based on numerous factors, including projections of future taxable income, which continues to be assessed based on available information each reporting period.
Total income tax expense for the three and six months ended June 30, 2019 differed from amounts computed by applying the U.S. federal statutory tax rates to pre-tax income primarily due to the release of the valuation allowance related to current period pre-tax book income and the impact of permanent differences between book and taxable income attributable to non-controlling interest. The effective tax rate includes a rate benefit attributable to the fact that Ranger LLC operates as a limited liability company treated as a partnership for federal and state income tax purposes and as such, is not subject to federal and state income taxes, except for the State of Texas for which Ranger LLC files with the Company. Accordingly, the portion of earnings attributable to non-controlling interest is subject to tax when reported as a component of the non-controlling interest’s taxable income.
Note 14 — Non-Controlling InterestsThe Company is subject to the following material taxing jurisdictions: the United States and Texas. As of June 30, 2019, the Company has no current tax years under audit. The Company remains subject to examination for federal income taxes and state income taxes for tax years 2017 and 2016.
The Company has ownership interests in Ranger LLC,evaluated all tax positions for which is consolidated within the Company’s financial statements but isstatute of limitations remains open and believes that the material positions taken would more likely than not wholly owned by the Company. During the nine months ended Septemberbe sustained upon examination. Therefore, as of June 30, 2018,2019, the Company reports a non-controlling interest representing the Ranger Units. Changes in the Company’s ownership interest in Ranger LLC while it retains its controlling interest are accountedhad not established any reserves for, as equity transactions.nor recorded any unrecognized benefits related to, uncertain tax positions.


Note 1512 — Earnings (Loss) per Share
Earnings (loss) per share is based on the amount of net income or loss allocated to the shareholders and the weighted average number of shares outstanding during the period for each class of Common Stock.
Earnings (losses) related to periods prior to the reorganization and the Offering are attributable to the Predecessor. The Company’s calculation of basic and diluted earnings (loss) per share for
  Three Months Ended Six Months Ended
  June 30, June 30,
  2019 2018 2019 2018
Income (loss) (numerator):        
Basic:        
Net income (loss) attributable to Ranger Energy Services, Inc. $1.0
 $(0.7) $3.0
 $(6.4)
Less: Undistributed earnings allocable to Class B Common Stock —
 —
 —
 —
Net income (loss) attributable to Class A Common Stock $1.0
 $(0.7) $3.0
 $(6.4)
         
Diluted:        
Net income (loss) attributable to Ranger Energy Services, Inc. $1.0
 $(0.7) $3.0
 $(6.4)
Less: Undistributed earnings allocable to Class B Common Stock —
 —
 —
 —
Net income (loss) attributable to Class A Common Stock $1.0
 $(0.7) $3.0
 $(6.4)
         
Weighted average shares (denominator):        
Weighted average number of shares - basic 8,514,495
 8,414,557
 8,481,788
 8,413,871
Weighted average number of shares - diluted 9,491,684
 8,414,557
 9,458,977
 8,413,871
         
Basic income (loss) per share $0.12
 $(0.08) $0.35
 $(0.76)
Diluted income (loss) per share $0.11
 $(0.08) $0.32
 $(0.76)
During the three and ninesix months ended SeptemberJune 30, 20182019 and 2017 are as follows (dollars in millions, except share and per share amounts):
  Three Months Ended September 30, Nine Months Ended September 30,
  2018 2017 2018 2017
Income (loss) (numerator):        
Basic:        
Net income (loss) attributable to Ranger Energy Services, Inc. $2.1
 $(3.5) $(4.3) $(3.5)
Less: Undistributed earnings allocable to Class B Common Stock —
 —
 —
 —
Net income (loss) attributable to Class A Common Stock $2.1
 $(3.5) $(4.3) $(3.5)
         
Diluted:        
Net income (loss) attributable to Ranger Energy Services, Inc. $2.1
 $(3.5) $(4.3) $(3.5)
Less: Undistributed earnings allocable to Class B Common Stock —
 —
 —
 —
Net income (loss) attributable to Class A Common Stock $2.1
 $(3.5) $(4.3) $(3.5)
         
Weighted average shares (denominator):        
Weighted average number of shares - basic 8,910,260
 8,413,178
 8,897,319
 8,413,178
Weighted average number of shares - diluted 9,156,872
 8,413,178
 8,897,319
 8,413,178
         
Basic income (loss) per share $0.24
 $(0.42) $(0.48) $(0.42)
Diluted income (loss) per share $0.23
 $(0.42) $(0.48) $(0.42)
For the periods presented above,2018, the Company excluded 6.9 million shares of Common Stock issuable upon conversion of the Company’s Class B Common Stock in calculating diluted loss per share, as the effect was anti-dilutive. During the three and six months ended June 30, 2018, the Company excluded 0.5 million equity-based compensation awards in calculating diluted loss per share, as the effect was anti-dilutive.


Note 1613 — CommitmentCommitments and Contingencies
Legal Matters
From time to time, the Company is involved in various legal matters arising in the normal course of business. The Company does not believe that the ultimate resolution of these currently pending matters will have a material adverse effect on its condensed consolidated financial position or results of operations.
Employee Severance
During 2017,the year ended December 31, 2018, the Company terminatedprovided notice to ESCO Leasing, LLC that the employmentCompany sought to be indemnified for breach of onecontract. The Company exercised the right to stop payments of the remaining principal balance of $5.8 million on the Seller's Notes and any unpaid interest, pending resolution of certain indemnification claims.
Note 14 — Segment Reporting
Historically, the Company reported two segments, with corporate general and administrative expense categorized as other. During the fourth quarter of 2018, the Company bifurcated the legacy Well Services segment into High Specification Rigs and Completion and Other Services due to the modifications made to its officers.internal reporting and responsibilities of those reporting to the Chief Operating Decision Maker (“CODM”). As a result, the former officer became entitledfinancial information being provided to severance payments of $0.7 million. In addition, the Company severed other officers and employees during the nine months ended September 30, 2018. As of September 30, 2018, the CompanyCODM has $0.5 million of severance liability recordedbeen updated to align with our new internal organization, which resulted in the accompanying condensed consolidated financial statements within accrued expenses.
Note 17 — Segment Reportinga new reportable segment discussed further below.
The Company’s operations are all located in the United States and organized into twothree reportable segments: WellHigh Specification Rigs, Completion and Other Services and Processing Solutions. The Company’sOur reportable segments comprise the structure used by its Chief Operating Decision Maker (“CODM”)our CODM to make key operating decisions and assess performance during the years presented in the accompanying condensed consolidated financial statements. The Company’sOur CODM evaluates the segments’ operating performance based on multiple measures including Operating income (loss), Adjusted Earnings before Interest, Tax, Depreciation and Amortization (“Adjusted EBITDA”),EBITDA, rig hours and rig utilization. The tables below present the operating income (loss) measurement, as the Company believes this is most consistent with the principals used in measuring the condensed consolidated financial statements.


We have made certain reclassifications to our prior period operating revenue, cost of sales and general and administrative amounts due to the change in reportable segments whereby our High Specification Rig and Completion and Other Services segments were bifurcated from our legacy Well Services segment as a result of our fourth quarter 2018 operating segment changes. None of these reclassifications have an impact on our condensed consolidated operations results, cash flows or financial position.
The following is a description of the segments:each operating segment:
Well Services.High Specification Rigs.  The Company’s well service rigsHigh Specification Rigs facilitate operations throughout the lifecycle of a well, including (i) well completion, support; (ii) workover;workover, (iii) well maintenance and (iv) decommissioning. The Company provides these advanced well services to exploration & production (“E&P”) companies, particularly to those operating in unconventional oil and natural gas reservoirs and requiring technically and operationally advanced services. The Company’s well serviceOur high specification rigs are designed to support growing U.S. horizontal well demands. In addition
Completion and Other Services.  Our Completion and Other Services segment provides services necessary to its corebring and maintain a well service rig operations, the Company offers a suiteon production and consists primarily of complementaryour wireline and snubbing lines of business along with other, non-rig well services, including wireline, snubbing,such as fluid management and well service-relatedservices-related equipment rentals.
Processing Solutions.  The Company provides a range of proprietary, modular equipment for the processing of rich natural gas streams at the wellhead or central gathering points in basins where drilling and completion activity has outpaced the development of permanent processing infrastructure.
Other. The Company incurs costs, indicated as Other, that are not allocable to eitherany of the operating segments, and includes mostly corporate general and administrative expenses as well as depreciation of office furniture and fixtures and other corporate assets. Prior to the Offering and subsequent reorganization, the Well Services and Processing Solutions segments were run as separate companies, therefore there were no such costs or assets.


Segment information as of SeptemberJune 30, 20182019 and December 31, 20172018 and for the three and ninesix months ended SeptemberJune 30, 20182019 and 20172018 is as follows (in millions):
  Other Well Services 
Processing
Solutions
 Total
  Three months ended September 30, 2018
Revenues $—
 $78.1
 $4.0
 $82.1
Cost of services $—
 $61.8
 $1.8
 $63.6
Depreciation and amortization $0.2
 $6.8
 $0.5
 $7.5
Impairment of goodwill $—
 $—
 $—
 $—
Operating income (loss) $(4.8) $9.5
 $(0.3) $4.4
Interest expense, net $(0.9) $—
 $—
 $(0.9)
Net income (loss) $(8.2) $11.0
 $1.2
 $4.0
Capital expenditures $—
 $20.0
 $2.0
 $22.0
  Nine months ended September 30, 2018
Revenues $—
 $206.9
 $10.9
 $217.8
Cost of services $—
 $167.7
 $5.1
 $172.8
Depreciation and amortization $0.6
 $18.9
 $1.1
 $20.6
Impairment of goodwill $—
 $9.0
 $—
 $9.0
Operating income (loss) $(19.2) $11.1
 $2.7
 $(5.4)
Interest expense, net $(1.8) $—
 $—
 $(1.8)
Net income (loss) $(21.3) $11.1
 $2.7
 $(7.5)
Capital expenditures $0.5
 $50.5
 $5.1
 $56.1
  As of September 30, 2018
Property, plant and equipment, net $6.4
 $192.5
 $31.8
 $230.7
Total assets $6.4
 $262.6
 $36.0
 $305.0
 Other Well Services 
Processing
Solutions
 Total Three months ended June 30, 2019
 Three months ended September 30, 2017 High Specification Rigs Completion and Other Services Processing Solutions Other Total
Revenues $—
 $39.0
 $2.1
 $41.1
 $33.1
 $46.3
 $4.9
 $—
 $84.3
Cost of services $—
 $33.1
 $0.8
 $33.9
 28.7
 35.0
 1.9
 —
 65.6
Depreciation and amortization $—
 $3.8
 $0.3
 $4.1
 4.8
 2.9
 0.5
 0.2
 8.4
Operating income (loss) $—
 $(5.2) $0.4
 $(4.8) (0.4) 8.4
 2.5
 (6.5) 4.0
Interest expense, net $—
 $(4.3) $—
 $(4.3) —
 —
 —
 (1.9) (1.9)
Net income (loss) $—
 $(9.9) $0.4
 $(9.5) (0.4) 8.4
 2.5
 (8.7) 1.8
Capital expenditures $—
 $8.2
 $1.1
 $9.3
 $1.2
 $1.8
 $2.4
 $—
 $5.4
 Nine Months Ended September 30, 2017 Six months ended June 30, 2019
Revenues $—
 $97.9
 $5.9
 $103.8
 $64.8
 $97.9
 $9.9
 $—
 $172.6
Cost of services $—
 $81.1
 $2.2
 $83.3
 56.1
 72.9
 4.1
 —
 133.1
Depreciation and amortization $—
 $10.9
 $0.8
 $11.7
 9.6
 5.7
 1.0
 0.5
 16.8
Operating income (loss) $—
 $(16.0) $0.8
 $(15.2) (0.9) 19.3
 4.8
 (14.0) 9.2
Interest expense, net $—
 $(5.8) $(0.1) $(5.9) —
 —
 —
 (3.2) (3.2)
Net income (loss) $—
 $(22.3) $0.8
 $(21.5) (0.9) 19.3
 4.8
 (17.8) 5.4
Capital expenditures $—
 $15.2
 $1.2
 $16.4
 $4.0
 $3.6
 $6.5
 $0.5
 $14.6
 As of December 31, 2017 As of June 30, 2019
Property, plant and equipment, net $6.4
 $157.4
 $25.4
 $189.2
 $134.7
 $47.6
 $39.8
 $5.6
 $227.7
Total assets $6.4
 $225.1
 $28.2
 $259.7
 $196.7
 $69.5
 $43.5
 $8.2
 $317.9


  Three Months Ended June 30, 2018
  High Specification Rigs Completion and Other Services Processing Solutions Other Total
Revenues $39.6
 $29.5
 $4.0
 $—
 $73.1
Cost of services 33.6
 21.8
 1.9
 —
 57.3
Depreciation and amortization 4.6
 1.8
 0.4
 0.2
 7.0
Impairment of goodwill —
 —
 —
 —
 —
Operating income (loss) 1.4
 5.9
 1.7
 (8.0) 1.0
Interest expense, net —
 —
 —
 (0.5) (0.5)
Net income (loss) 1.4
 5.9
 1.7
 (10.2) (1.2)
Capital expenditures $16.7
 $3.7
 $0.9
 $0.5
 $21.8
  Six Months Ended June 30, 2018
Revenues $75.9
 $52.9
 $6.9
 $—
 $135.7
Cost of services 65.1
 40.2
 3.3
 —
 108.6
Depreciation and amortization 8.6
 3.5
 0.6
 0.4
 13.1
Impairment of goodwill 9.0
 —
 —
 —
 9.0
Operating income (loss) (6.8) 9.2
 3.0
 (15.2) (9.8)
Interest expense, net —
 —
 —
 (0.9) (0.9)
Net income (loss) (6.8) 9.2
 3.0
 (16.9) (11.5)
Capital expenditures $25.0
 $5.5
 $3.1
 $0.5
 $34.1
  As of December 31, 2018
Property, plant and equipment, net $159.2
 $35.0
 $34.3
 $1.3
 $229.8
Total assets $214.1
 $47.0
 $40.1
 $1.3
 $302.5


Note 18 — Subsequent Events
In October 2018, we borrowed an additional $9.9 million, net of expenses, under our Financing Agreement. We anticipate utilizing the net proceeds to acquire certain capital equipment.
In October 2018, we provided notice to ESCO Leasing, LLC that we are seeking to be indemnified for breach of the contract. We exercised our right to stop payments of the remaining principal balance of $5.8 million on the Seller's Notes, and any unpaid interest.
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 financial statements and related notes included in Part I, Item 1. Financial Statements of this Quarterly Report on Form 10-Q (the “Quarterly Report”). This discussion contains “forward‑looking statements” reflecting our current expectations, 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. Factors that could cause or contribute to such differences include, but are not limited to, market prices for oil and natural gas, capital expenditures, economic and competitive conditions, regulatory changes and other uncertainties, as well as those factors discussed below and elsewhere in this report. Please read Cautionary Note Regarding Forward‑Looking Statements. Also, please read the risk factors and other cautionary statements described under Part II, Item 1A.-“Risk Factors” included elsewhere in this Quarterly Report and in our Annual Report.Report filed on Form 10-K for the years ended December 31, 2018 and 2017. We assume no obligation to update any of these forward‑looking statements.
Overview
We areThe Company is one of the largest providers of high specification (“high‑specspec”) well service rigs and complimentaryassociated services in the United States, with a focus on technically demanding unconventional horizontal well completion and production operations. We believe that our fleet of 136141 well service rigs areis among the newest and most advanced in the industry and, based on our historical rig utilization and feedback from our customers, we believe that we are an operator of choice for U.S. onshore exploration and production (“E&P&P”) companies that require completion and production services at increasing lateral lengths. Our high‑spec well service rigs facilitate operations throughout the lifecycle of a well, including (i) well completion support, such as milling out composite plugs used during hydraulic fracturing; (ii) workover, including retrieval and replacement of existing production tubing; (iii) well maintenance, including replacement of downhole artificial lift components and (iv) decommissioning, such as plugging and abandonment operations. In addition to our core well service rig operations, we offer a suite of complementary services, including wireline, snubbing, well testing, fluid management and well service-related equipment rentals. We also provide rental equipment, including well control packages, hydraulic catwalks and other equipment that are often deployed with our well service rigs. In addition, we own and operate a fleet of proprietary, modular natural gas processing equipment that processes rich natural gas streams at the wellhead or central gathering points. We haveThe Company has operations in most of the active oil and natural gas basins in the United States, including the Permian Basin, the Denver‑Julesburg Basin, the Bakken Shale, the Eagle Ford Shale, the Haynesville Shale, and the Gulf Coast and the SCOOPSouth Central Oklahoma Oil Province and STACKSooner Trend Anadarko Basin Canadian and Kingfisher counties plays.
Our Predecessor and Ranger Energy Services, Inc.
The Company was formed on February 17, 2017, and did not conduct any material business operations prior to the transactions described under “–Initial Public Offering” other than certain activities related to the Offering. Our Predecessor consists of Ranger Services and Torrent Services on a combined consolidated basis. In connection with the transactions described in Note 1 — Organization and Business Operations – Reorganization to the unaudited interim condensed consolidated financial statements, the Existing Owners contributed the equity interests in the Predecessor Companies to us in exchange for shares of our Class A Common Stock, Ranger Units and shares of our Class B Common Stock.
Ranger Services was, through Ranger Holdings, formed by CSL in June 2014 as a provider of high‑spec well service rigs and associated services. Torrent Services was, through Torrent Holdings, acquired by CSL in September 2014 as a provider of proprietary, modular equipment for the processing of natural gas. In June 2016, CSL indirectly acquired substantially all of the assets of Magna, a provider of well services and wireline services, which it contributed to Ranger Services in September 2016. In October 2016, Ranger Services acquired substantially all of the assets of Bayou, an owner and operator of high‑spec well service rigs. The historical condensed consolidated financial information included in this Quarterly Report presents (i) prior to August 16, 2017, the historical financial information of the Predecessor Companies, including, as applicable, the results of operations of Magna and Bayou for periods subsequent to their respective acquisitions and (ii) subsequent to August 16, 2017, the historical financial information of the Company. The historical condensed consolidated financial information of our Predecessor is not indicative of the results that may be expected in any future periods. For more information, please see the historical condensed consolidated related notes thereto included elsewhere in this Quarterly Report.
On August 16, 2017, we acquired 49 high-spec well service rigs, certain ancillary equipment and certain liabilities. The ESCO Acquisition is included in our consolidated financial results from the date of acquisition onward.


We conduct our operations through twothree segments: WellHigh Specification Rigs, Completion and Other Services and Processing Solutions. Solutions, as described below.
Our WellHigh Specification Rig Services segment has historically consisted of the results of operations of Ranger Services and, as applicable, Magna, Bayou and the ESCO Acquisition assets from their respective acquisition dates, while our Processing Solutions segment has historically consisted of the results of operations of Torrent Services. Our Well Services segment provides high‑spec well service rigs and complementary equipment and services in the United States, with a focus on technically demanding unconventional horizontal well completion, workover and maintenance operations. These services are fundamental to establishing and maintaining the flow of oil and natural gas throughout the productive life of a well. Our high‑specification well service rigs facilitate operations throughout the lifecycle of a well, including (i) completion services, such as milling out composite plugs after the hydraulic fracturing process and the installation of downhole production equipment; (ii) workover, including retrieval and replacement of existing production tubing; (iii) well maintenance, including replacement of downhole artificial lift components; and (iv) decommissioning, such as plugging and abandonment operations.
The Company also provides Completion and Other Services, which provides services necessary to bring and maintain a well on production and primarily includes (i) wireline perforating and pumpdown services and (ii) snubbing services often utilized in conjunction with our high-spec rigs to convey equipment in and out of a well during completion and workover activities. The Company provides rental equipment, including well control packages, hydraulic catwalks and other equipment that are often deployed with our well service rigs.
Our Processing Solutions segment engages in the rental, installation, commissioning, start‑up, operation and maintenance of mechanical refrigeration unitsMechanical Refrigeration Units (“MRUs”MRU”), NGLNatural Gas Liquid (“NGL”) stabilizer units, NGL storage units and related equipment. We operate in mostIn addition, the Company owns and operates a fleet of the active oil andproprietary, modular natural gas basins inprocessing equipment that processes rich natural gas streams at the United States, includingwellhead or central gathering points.
For further information regarding the Permian Basin, the Denver‑Julesburg Basin, the Bakken Shale, the Eagle Ford Shale, the Haynesville Shale, the Gulf Coast and the SCOOP and STACK plays. For additional information about our assets andresults of operations for each segment, please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Results of Operations” in Item 2 and Part I, Note 1713 — Segment Reporting, to the unaudited interim condensed consolidated financial statements.
Initial Public Offering
On August 16, 2017, we completed the OfferingCommitments and Contingencies of 5,862,069 shares of our Class A Common Stock. The gross proceeds of the Offering, based on a public offering price of $14.50 per share, was $85.0 million, which resulted in net proceeds to us of $77.0 million, after deducting $4.2 million of underwriting discounts and commissions and $3.9 million of costs related to the Offering.  These net proceeds were used to pay off the remainder of our long term debt of $10.4 million, fund $45.2 million for the cash portion of the ESCO Acquisition, and $0.7 million for cash bonuses to certain employees. The remaining $20.7 million of net proceeds were used to fund capital expenditures and general business expenses. this Quarterly Report.
How We Generate Revenues
We currently generate revenues through the provision of a variety of oilfield services. These services are performed under a variety of contract structures, including a long term take‑or‑pay contract and various master service agreements, as supplemented by statements of work, pricing agreements and specific quotes. A portion of our master services agreements include provisions that establish pricing arrangements for a period of up to one year in length. However, the majority of those agreements provide for pricing adjustments based on market conditions. The majority of our services are priced based on prevailing market conditions and changing input costs at the time the services are provided, giving consideration to the specific requirements of the customer.
In determining the appropriate amount of revenue to be recognized as we fulfill the obligations under its contracts with customers, the following steps must be performed at contract inception: (i) identification of the promised goods or services in the


contract; (ii) determination of whether the promised goods or services are performance obligations, including whether they are distinct in the context of the contract; (iii) measurement of the transaction price, including the constraint on variable consideration; (iv) allocation of the transaction price to the performance obligation and (v) recognition of revenue when (or as) the Company satisfies each performance obligation.
We satisfy our performance obligation over time as the services are performed. The Company believes the output method is a reasonable measure of progress for the satisfaction of our performance obligations, which are satisfied over time, as it provides a faithful depiction of (i) our performance towards complete satisfaction of the performance obligation under the contract and (ii) the value transferred to the customer of the services performed under the contract. We invoice our customers upon completion of the specified services and collection generally occurs within the payment terms agreed with customers. Accordingly, there is no financing component to our arrangement with customers. Please see Note 32 — Revenue from Contracts with Customers toSummary of Significant Accounting Policies of the unaudited interim condensed consolidated financial statements.Annual Report.
Costs of Conducting Our Business
The principal expenses involved in conducting our business are personnel, repairs and maintenance costs, general and administrative, depreciation and amortization and interest expense. We manage the level of our expenses, except depreciation and amortization and interest expense, based on several factors, including industry conditions and expected demand for our services. In addition, a significant portion of the costs we incur in our business is variable based on the quantities of specific services provided and the requirements of such services.
Direct cost of services and general and administrative expenses include the following major cost categories: personnel costs and equipment costs (including repair and maintenance).
Personnel costs associated with our operational employees represent a significant cost of our business. A substantial portion of our labor costs is attributable to our crews and is partly variable based on the requirements of specific customers and operations. A key component of personnel costs relates to the ongoing training of our employees, which improves safety rates and reduces attrition. We also incur costs to employ personnel to support our services and perform maintenance on our assets. Costs for these employees are not directly tied to our level of business activity.
We incur significant equipment costs in connection with the operation of our business, including repair and maintenance costs.
How We Evaluate Our Operations
Our managementManagement uses a variety of metrics to analyze our operating results and profitability. These metrics include, among others, the following:
Revenues;
Operating Income (Loss);operating revenues, operating income (loss) and
Adjusted EBITDA.
In addition, withinWithin our Well ServicesHigh Specification Rig segment, our management intends to useuses additional metrics to analyze our activity levels and profitability. These metrics include, among others, the following:
Rig Hours;rig hours and


Rig Utilization. rig utilization.
Revenues
We analyze our revenues by comparing actual revenues to our internal projections for a given period and to prior periods to assess our performance. We believe that revenues are a meaningful indicator of the demand and pricing for our services.
Operating Income (Loss)
We analyze our operating income (loss), which we define as revenues less cost of services, general and administrative expenses, depreciation and amortization, impairment and other operating expenses, to measure our financial performance. We believe operating income (loss) is a meaningful metric because it provides insight on profitability and true operating performance based on the historical cost basis of our assets. We also compare operating income (loss) to our internal projections for a given period and to prior periods.
Adjusted EBITDA
We view Adjusted EBITDA, which is a non‑GAAP financial measure, as an important indicator of performance. We define Adjusted EBITDA as net income (loss) before interest expense, net, income tax provision (benefit),or benefit, depreciation and amortization, equity‑based compensation, acquisition‑related and severance costs, impairment of goodwill, gain or loss on sale of assets and other non-cash and certain other items that we do not view as indicative of our ongoing performance. See “Results of Operations—Note Regarding Non‑GAAP Financial Measure” for more information and reconciliations of net income (loss) to Adjusted EBITDA, the most directly comparable financial measure calculated and presented in accordance with GAAP.


Rig Hours
Within our Well ServicesHigh Specification Rig segment, we analyze rig hours as an important indicator of our activity levels and profitability. Rig hours represent the aggregate number of hours that our well service rigs actively worked during the periods presented. We typically bill customers for our well services on an hourly basis during the period that a well service rig is actively working, making rig hours a useful metric for evaluating our profitability.
Rig Utilization
Within our Well ServicesHigh Specification Rig segment, we analyze rig utilization as a further important indicator of our activity levels and profitability. We measure rig utilization by reference to average monthly hours per rig, which is calculated by dividing (a) the approximate, aggregate operating well service rig hours for the periods presented by (b) the aggregate number of well servicehigh specification rigs in our fleet during such period, as aggregated on a monthly basis utilizing a mid-month convention whereby a well servicehigh specification rig added to our fleet during a month, meaning that we have taken delivery of such well servicehigh specification rig and it is ready for service, and is then assumed to be in our fleet for one half of such month. We believe that rig utilization as measured by average monthly hours per well servicehigh specification rig is a meaningful indicator of the operational efficiency of our core revenue-producing assets, market demand for our well services and our ability to profitably capitalize on such demand. Our evaluation of our rig utilization as measured by average monthly hours per rig may not be comparable to that of our competitors.
The primary factors that have historically impacted, and will likely continue to impact, our actual aggregate well service rig hours for any specified period areare: (i) customer demand, which is influenced by factors such as commodity prices, the complexity of well completion operations and technological advances in our industry, and (ii) our ability to meet such demand, which is influenced by changes in our fleet size and resulting rig availability, as well as weather, employee availability and related factors. The primary factors that have historically impacted, and will likely continue to impact, the aggregate number of well servicehigh specification rigs in our fleet during any specified period are the extent and timing of changes in the size of our well service rig fleet to meet short-term and expected long-term demand, and our ability to successfully maintain a fleet capable of ensuring sufficient, but not excessive, rig availability to meet such demand.
For the ninethree months ended SeptemberJune 30, 20182019 and 2017,2018, our rig utilization as measured by average monthly hours per rig was approximately 183147 hours and 196187 hours, respectively. Actual aggregate operating well service rig hours increaseddecreased from approximately 137,50076,200 in the ninethree months ended SeptemberJune 30, 2017,2018 to approximately 224,60062,200 in the ninethree months ended SeptemberJune 30, 2018.2019. The increasedecrease in rig hours resulted fromwas partially offset by an increase in the average number of well service rigs in our active fleet from 78 during the nine months ended September 30, 2017 to 136 during the nine months ended September 30, 2018, and a corresponding increase in our potential aggregate well service rig hours. For the nine months ended September 30, 2018 and 2017, our average revenue per rig hour was approximately $505to $530 from $513 for the three months ended June 30, 2019 and $448,2018, respectively.
For the threesix months ended SeptemberJune 30, 20182019 and 2017,2018, our rig utilization, as measured by average monthly hours per rig, was approximately 178145 hours and 199186 hours, respectively. Actual aggregate operating well service rig hours increaseddecreased from approximately 59,300149,800 in the threesix months ended SeptemberJune 30, 20172018, to approximately 74,200122,300 in the threesix months ended SeptemberJune 30, 2018.2019. The increasedecrease in rig hours resulted fromwas partially offset by an increase in the average number of well service rigs in our active fleet from 99 during the three months ended September 30, 2017 to 139 during the three months ended September 30, 2018, and a corresponding


increase in our potential aggregate well service rig hours. For the three months ended September 30, 2018 and 2017, our average revenue per rig hour was approximately $519to $526 from $500 for the six months ended June 30, 2019 and $443,2018, respectively.
Factors Impacting the Comparability of Results of Operations
ESCO Acquisition
Our Predecessor’s historical condensed consolidated financial statements for the three months ended September 30, 2017 and the majority of the nine months ended September 30, 2017 do not include the results of operations for the assets we acquired in the ESCO Acquisition. As a result, our Predecessor’s historical financial data does not give you an accurate indication of what our actual results would have been if the ESCO Acquisition had been completed at the beginning of the periods presented or of what our future results of operations are likely to be. Please see Note 4 — Acquisitions to the unaudited interim condensed consolidated financial statements, for the supplemental pro forma financial disclosures for the nine months ended September 30, 2017.
Reorganization
On August 10, 2017, we entered into the Master ReorganizationTax Receivable Agreement with, among others, Ranger LLC and the Existing Owners.
Subject to the terms and conditions set forth in the Master Reorganization Agreement, the parties thereto effected a series of restructuring transactions in connection with the Offering of Class A Common Stock, as a result of which:
(i) Ranger Holdings II and Torrent Holdings II contributed certain of the equity interests in the Predecessor Companies to the Company in exchange for an aggregate of 1,683,386 shares of Class A Common Stock and the Company contributed such equity interests to Ranger LLC in exchange for 1,638,386 units in Ranger LLC (“Ranger Units”). Additionally, an aggregate of $3.0 million will be paid by the Company to CSL Energy Holdings I, LLC, a Delaware limited liability company and CSL Energy Holdings II, LLC, a Delaware limited liability company, on or prior to the 18-month anniversary of the consummation of the Offering in, at the Company’s option, cash, shares of Class A Common Stock (with such shares to be valued based on the greater of the price of the Class A Common Stock in the Offering and a 30-day volume-weighted average price) or a combination thereof;
(ii) Ranger Holdings and Torrent Holdings contributed the remaining membership interests in the Predecessor Companies to Ranger LLC in exchange for 5,621,491 units in Ranger Units and 5,621,491 shares of the Company’s Class B Common Stock, which the Company issued and contributed to Ranger LLC; 
(iii) the Company contributed all of the net proceeds received by it in the Offering to Ranger LLC in exchange for 5,862,069 Ranger Units; 
(iv) Ranger LLC distributed to each of Ranger Holdings and Torrent Holdings one share of Class B Common Stock received pursuant to (ii) above for each Ranger Unit such Existing Owner held; and
(v) as consideration for the termination of certain loan agreements, the Company issued 567,895 shares of Class A Common Stock (in connection with which Ranger LLC issued 567,895 Ranger Units to the Company) and Ranger LLC issued an aggregate of 1,244,663 Ranger Units (and distributed a corresponding number of shares of Class B Common Stock) to the lenders thereof.
The foregoing transactions were undertaken in reliance on an exemption from the registration requirements of the Securities Act, pursuant to Section 4(a)(2) thereof. As a result of these transactions, Ranger LLC became a subsidiary of the Company and the Predecessor Companies became wholly owned subsidiaries of Ranger LLC.
In connection with the Offering, we entered into a TRA with certain of the Ranger Unit holders and their permitted transferees (each such person, a "TRA Holder"“TRA Holder” and, together, the "TRA Holders"“TRA Holders”). The TRA generally provides for the payment by us to each TRA Holder of 85% of the net cash savings, if any, in U.S. federal, state and local income tax and franchise tax that we actually realize (computed using the estimated impact of state and local taxes) or are deemed to realize in certain circumstances in periods following the Offering as a result of (i) certain increases in tax basis that occur as a result of our acquisition (or deemed acquisition for U.S. federal income tax purposes) of all or a portion of such TRA Holder'sHolder’s Ranger Units in connection with the Offering or pursuant to the exercise of the Redemption Right or the Call Right (each as defined in the Amended and Restated Limited Liability Company Agreement of Ranger LLC) and (ii) imputed interest deemed to be paid by us as a result of, and additional tax basis arising from, any payments we make under the TRA. We will retain the benefit of the remaining 15% of these cash savings.
Income Taxes
Ranger Inc. is a Subchapter C corporation under the Internal Revenue Code of 1986, as amended (the “Code”), and, as a result, is subject to U.S. federal, state and local income taxes. Although the Predecessor Companies are subject to franchise tax in the State of Texas (at less than 1% of modified pre‑tax earnings), they have historically passed through their taxable income to their owners for U.S. federal and other state and local income tax purposes and thus were not subject to U.S. federal income taxes or other state or local income taxes. Accordingly, the financial data attributable to our Predecessor contains no provision for U.S.


federal income taxes or income taxes in any state or locality other than franchise tax in the State of Texas. We account for income taxes under the asset and liability method. Under this method, deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates in effect for the year in which those temporary differences are expected to be recovered or settled pursuant to the provisions of ASC 740, Income Taxes.Taxes. The effect on deferred tax assets and liabilities of a change in tax rate is recognized in earnings in the period that includes the enactment date. Valuation allowances are established when necessary to reduce deferred tax assets to the amounts more likely than not to be realized. We currently believe that it is


reasonably possible for us to achieve a three-year cumulative level of profitability within the next 12 months, and as early as the third quarter of 2019, which would enhance our ability to conclude that is it more likely than not that the deferred tax assets would be realized and support a release of a portion or substantially all of the valuation allowance. A release of the valuation allowance would result in the recognition of an increase in deferred tax assets and an income tax benefit in the period in which the release occurs, although the exact timing and amount of the release is subject to change based on numerous factors, including our projections of future taxable income, which we continue to asses based on available information each reporting period.
Results of Operations
Three Months Ended SeptemberJune 30, 20182019 compared to Three Months Ended SeptemberJune 30, 20172018
The following table presents our Predecessor’s selectedthe operating dataresults for the three months ended SeptemberJune 30, 20182019 as compared to the three months ended SeptemberJune 30, 2017.2018.
 Three Months Ended    
 September 30, Change June 30, Change
 2018 2017 $ % 2019 2018 $ %
Revenues                
Well Services $78.1
 $39.0
 $39.1
 100 %
High Specification Rigs $33.1
 $39.6
 $(6.5) (16)%
Completion and Other Services 46.3
 29.5
 16.8
 57 %
Processing Solutions 4.0
 2.1
 1.9
 90 % 4.9
 4.0
 0.9
 23 %
Total revenues 82.1
 41.1
 41.0
 100 % 84.3
 73.1
 11.2
 15 %
Operating expenses       

        
Cost of services (exclusive of depreciation and amortization shown separately):       

        
Well Services 61.8
 33.1
 28.7
 87 %
High Specification Rigs 28.7
 33.6
 (4.9) (15)%
Completion and Other Services 35.0
 21.8
 13.2
 61 %
Processing Solutions 1.8
 0.8
 1.0
 125 % 1.9
 1.9
 —
 — %
Total cost of services 63.6
 33.9
 29.7
 88 % 65.6
 57.3
 8.3
 14 %
General and administrative 6.6
 7.9
 (1.3) (16)% 6.3
 7.8
 (1.5) (19)%
Depreciation and amortization 7.5
 4.1
 3.4
 83 % 8.4
 7.0
 1.4
 20 %
Impairment of goodwill —
 —
 —
 —
Total operating expenses 77.7
 45.9
 31.8
 69 % 80.3
 72.1
 8.2
 11 %
Operating income (loss) 4.4
 (4.8) 9.2
 192 %
Operating income 4.0
 1.0
 3.0
 300 %
Other expenses       

        
Interest expense, net (0.9) (4.3) (3.4) (79)% 1.9
 0.5
 1.4
 280 %
Total other expenses (0.9) (4.3) (3.4) (79)% 1.9
 0.5
 1.4
 280 %
Income (loss) before income tax expense 3.5
 (9.1) 12.6
 138 %
Income before income tax expense 2.1
 0.5
 1.6
 320 %
Tax expense (benefit) (0.5) 0.4
 (0.9) (225)% 0.3
 1.7
 (1.4) 82 %
Net income (loss) $4.0
 $(9.5) $13.5
 142 % $1.8
 $(1.2) $3.0
 250 %
Revenues. Revenues for the three months ended SeptemberJune 30, 20182019 increased $41.0$11.2 million, or 100%15%, to $82.1$84.3 million from $41.1$73.1 million for the three months ended SeptemberJune 30, 2017.2018. The increasechange in revenues by segment was as follows:
Well Services.High Specification Rigs. WellHigh Specification Rig revenues for the three months ended June 30, 2019 decreased $6.5 million, or 16%, to $33.1 million from $39.6 million for the three months ended June 30, 2018. The decrease in rig services revenue included an 18% decrease in total rig hours to 62,200 from 76,200 for the three months ended June 30, 2019 compared to the three months ended June 30, 2018. The reduction in total rig hours was partially offset by a 3% increase in average dayrates to $530 from $513 for the six months ended June 30, 2019 and 2018, respectively.
Completion and Other Services. Completion and Other Services revenues for the three months ended SeptemberJune 30, 2018 increased $39.12019 increased$16.8 million, or 100%57%, to $78.1$46.3 million from $39.0$29.5 million for the three months ended SeptemberJune 30, 2017.2018. The increase was dueis primarily attributable to an increased numberour wireline business, which accounted for approximately $13.6 million, or 81%, of rigs, to an average of 139 from an average of 99 rigs, providing workover rig services, which is primarilythe revenue increase, related to the ESCO Acquisition and accounted for $9.2 million, or 24%expansion of the segment increase.Company’s activities. The increase in workover rig services included a 25% increase in total rig hours to 74,200wireline unit count increased 86% from 59,300 for the three months ended Septemberseven units as of June 30, 2018 compared to the three months ended September13 as of June 30, 2017. In addition, our wireline business accounted for $28.8 million of the increase in revenues due to the fact that the majority of this business commenced operation in the Permian Basin during 2018.2019.
Processing Solutions. Processing Solutions revenues for the three months ended SeptemberJune 30, 20182019 increased $1.9$0.9 million, or 90%23%, to $4.0$4.9 million from $2.1$4.0 million for the three months ended SeptemberJune 30, 2017.2018. The increase was primarily attributable to the additional MRUs and tanks we have rented to customers as well as additional mobilizationan increase in MRU revenue due to equipment goinga 16% increase in MRU units from 25 units as of June 30, 2018 compared to customers.29 units as of June


30, 2019, and an increase in our rental rates. Additionally, there were increased revenues associated with our compressors, tanks and generator rentals.
Cost of services (excluding depreciation and amortization shown separately). Cost of services for the three months ended SeptemberJune 30, 20182019 increased $29.7$8.3 million, or 88%14%, to $63.6$65.6 million from $33.9$57.3 million for the three months ended SeptemberJune 30, 2017.2018. As a percentage of revenue, cost of services was 78% for both the three months ended June 30, 2019 and 2018. The change in cost of services by segment was as follows:
High Specification Rigs. High Specification Rig cost of services for the three months ended June 30, 2019 decreased $4.9 million, or 15% to $28.7 million from $33.6 million for the three months ended June 30, 2018. The decrease was primarily attributable to a reduction in variable expenses, notably employee costs and repair and maintenance costs, due to a decrease in rig hours.
Completion and Other Services. Completion and Other Services cost of services for the three months ended June 30, 2019 increased $13.2 million, or 61%, to $35.0 million from $21.8 million for the three months ended June 30, 2018. The increase was primarily attributable to an increase in expenses due to the expansion of the completion activities, primarily our wireline business, which includes increases in employee costs and cost of services.
Processing Solutions. Processing Solutions cost of services for the three months ended June 30, 2019 remained constant at $1.9 million for both the three months ended June 30, 2019 and 2018.
General & Administrative. General and administrative expenses for the three months ended June 30, 2019 decreased $1.5 million to $6.3 million from $7.8 million compared to the three months ended June 30, 2018. The decrease was attributable to employee-related costs and professional fees.
Depreciation and Amortization. Depreciation and amortization for the three months ended June 30, 2019 increased $1.4 million, or 20%, to $8.4 million from $7.0 million for the three months ended June 30, 2018. The increase is attributable to fixed assets added during the year ended December 31, 2018.
Interest Expense, net. Interest expense, net for the three months ended June 30, 2019 increased $1.4 million, or 280%, to $1.9 million from $0.5 million for the three months ended June 30, 2018. The increase to interest expense, net was attributable to the borrowings on our Encina Master Financing Agreement, which was entered into in June 2018, and increased borrowings under our Credit Facility.


Six Months Ended June 30, 2019 compared to Six Months Ended June 30, 2018
The following table presents the operating results for the six months ended June 30, 2019 as compared to the six months ended June 30, 2018.
 ��Six Months Ended    
  June 30, Change
  2019 2018 $ %
Revenues        
High Specification Rigs $64.8
 $75.9
 $(11.1) (15)%
Completion and Other Services 97.9
 52.9
 45.0
 85 %
Processing Solutions 9.9
 6.9
 3.0
 43 %
Total revenues 172.6
 135.7
 36.9
 27 %
Operating expenses        
Cost of services (exclusive of depreciation and amortization shown separately):        
High Specification Rigs 56.1
 65.1
 (9.0) (14)%
Completion and Other Services 72.9
 40.2
 32.7
 81 %
Processing Solutions 4.1
 3.3
 0.8
 24 %
Total cost of services 133.1
 108.6
 24.5
 23 %
General and administrative 13.5
 14.8
 (1.3) (9)%
Depreciation and amortization 16.8
 13.1
 3.7
 28 %
Impairment of goodwill —
 9.0
 (9.0) (100)%
Total operating expenses 163.4
 145.5
 17.9
 12 %
Operating income 9.2
 (9.8) 19.0
 (194)%
Other expenses        
Interest expense, net 3.2
 0.9
 2.3
 (256)%
Total other expenses 3.2
 0.9
 2.3
 (256)%
Income before income tax expense 6.0
 (10.7) 16.7
 156 %
Tax expense (benefit) 0.6
 0.8
 (0.2) (25)%
Net income (loss) $5.4
 $(11.5) $16.9
 147 %
Revenues. Revenues for the six months ended June 30, 2019 increased $36.9 million, or 27%, to $172.6 million from $135.7 million for the six months ended June 30, 2018. The increase in revenues by segment was as follows:
High Specification Rigs. High Specification Rigs revenues for the six months ended June 30, 2019 decreased $11.1 million, or 15%, to $64.8 million from $75.9 million for the six months ended June 30, 2018. The decrease in rig services revenue included an 18% reduction in total rig hours to 122,300 hours for the six months ended June 30, 2019 from 149,800 for the six months ended June 30, 2018. The reduction in total rig hours was partially offset by a 5% increase in average dayrates to $526 from $500 for the six months ended June 30, 2019 and 2018, respectively.
Completion and Other Services. Completion and Other Services revenues for the six months ended June 30, 2019 increased $45.0 million, or 85%, to $97.9 million from $52.9 million for the six months ended June 30, 2018. The increase is primarily attributable to our wireline business, which accounted for approximately $39.5 million, or 88%, of the revenue increase, attributable to the expansion of the Company’s activities. The wireline unit count increased 86% from seven units as of June 30, 2018 compared to 13.0 as of June 30, 2019.
Processing Solutions. Processing Solutions revenues for the six months ended June 30, 2019 increased $3.0 million, or 43%, to $9.9 million from $6.9 million for the six months ended June 30, 2018. The increase was primarily attributable to an increase in MRU revenue due to a 16% increase in MRU units from 25 units as of June 30, 2018 compared to 29 units as of June 30, 2019, and an increase in our rental rates. Additionally, there were increased revenues associated with our compressors, tanks and generator rentals.
Cost of services (excluding depreciation and amortization shown separately). Cost of services for the six months ended June 30, 2019 increased $24.5 million, or 23%, to $133.1 million from $108.6 million for the six months ended June 30, 2018. As a percentage of revenue, cost of services was 77% and 82%80% for the threesix months ended SeptemberJune 30, 20182019 and 2017,2018, respectively. The increase in cost of services by segment was as follows:


Well Services.High Specification Rigs. WellHigh Specification Rigs cost of services for the six months ended June 30, 2019 decreased $9.0 million, or 14%, to $56.1 million from $65.1 million for the six months ended June 30, 2018. The decrease was primarily attributable to a reduction in variable expenses, notably employee costs and repair and maintenance costs, due to a decrease in rig hours.
Completion and Other Services. Completion and Other Services cost of services for the threesix months ended SeptemberJune 30, 20182019 increased $28.7$32.7 million, or 87%81%, to $61.8$72.9 million from $33.1$40.2 million for the threesix months ended SeptemberJune 30, 2017.2018. The increase was primarily attributable to an increase in expenses due to the expansion of the Company’s activities; notablycompletion activities, primarily our wireline business, which includes increases in employee costs and repair and maintenance costs.cost of services.
Processing Solutions. Processing Solutions cost of services for the threesix months ended SeptemberJune 30, 20182019 increased $1.0$0.8 million, or 125%24%, to $1.8$4.1 million from $0.8$3.3 million for the threesix months ended SeptemberJune 30, 2017. The increase was primarily attributable to increases in new equipment and the mobilization costs incurred which corresponds with additional revenues.
General & Administrative. General and administrative expenses for the three months ended September 30, 2018 decreased $1.3 million, or 16%, to $6.6 million from $7.9 million for the three months ended September 30, 2017. The decrease in general and administrative expenses by segment was as follows:
Well Services and other.  Well Services general and administrative expenses for the three months ended September 30, 2018 decreased $1.3 million, or 18%, to $5.9 million from $7.2 million for the three months ended September 30, 2017. The decrease was primarily attributable to a decrease in expenses due to the expenses for professional costs and other costs associated with the Offering in 2017.
Processing Solutions. Processing Solutions general and administrative expenses remained constant at $0.7 million for the three months ended September 30, 2018 and 2017.
Depreciation and Amortization. Depreciation and amortization for the three months ended September 30, 2018 increased $3.4 million, or 83%, to $7.5 million from $4.1 million for the three months ended September 30, 2017. The increase in depreciation and amortization expense by segment was as follows:
Well Services and other.  Well Services depreciation and amortization expense for the three months ended September 30, 2018 increased $3.2 million, or 84%, to $7.0 million from $3.8 million for the three months ended September 30, 2017. The increase was primarily attributable to fixed assets that were put in service during 2017 and the nine months ended September 30, 2018, which includes the assets acquired as part of the ESCO Acquisition.
Processing Solutions. Processing Solutions depreciation expense was $0.5 million for the three months ended September 30, 2018 compared to $0.3 million for the three months ended September 30, 2017.
Interest Expense, net. Interest expense, net for the three months ended September 30, 2018 decreased $3.4 million, or 79%, to $0.9 million from $4.3 million for the three months ended September 30, 2017. The decrease to interest expense, net was attributable to the repayment of the Bridge Loans during 2017 by issuing Class A Common Stock and Ranger Units (and corresponding number of shares of our Class B Common Stock) to the Bridge Loan Lenders.


Nine Months Ended September 30, 2018 compared to Nine Months Ended September 30, 2017
The following table presents our Predecessor’s selected operating data for the nine months ended September 30, 2018 as compared to the nine months ended September 30, 2017.
  September 30, Change
  2018 2017 $ %
Revenues        
Well Services $206.9
 $97.9
 $109.0
 111 %
Processing Solutions 10.9
 5.9
 5.0
 85 %
Total revenues 217.8
 103.8
 114.0
 110 %
Operating expenses        
Cost of services (exclusive of depreciation and amortization shown separately):        
Well Services 167.7
 81.1
 86.6
 107 %
Processing Solutions 5.1
 2.2
 2.9
 132 %
Total cost of services 172.8
 83.3
 89.5
 107 %
General and administrative 20.8
 24.0
 (3.2) (13)%
Depreciation and amortization 20.6
 11.7
 8.9
 76 %
Impairment of goodwill 9.0
 —
 9.0
 100 %
Total operating expenses 223.2
 119.0
 104.2
 88 %
Operating loss (5.4) (15.2) (9.8) (64)%
Other expenses        
Interest expense, net (1.8) (5.9) (4.1) (69)%
Total other expenses (1.8) (5.9) (4.1) (69)%
Loss before income tax expense (7.2) (21.1) (13.9) (66)%
Tax expense (benefit) 0.3
 0.4
 (0.1) (25)%
Net loss $(7.5) $(21.5) $(14.0) (65)%
Revenues. Revenues for the nine months ended September 30, 2018 increased $114.0 million, or 110%, to $217.8 million from $103.8 million for the nine months ended September 30, 2017. The increase in revenues by segment was as follows:
Well Services. Well Services revenues for the nine months ended September 30, 2018 increased $109.0 million, or 111%, to $206.9 million from $97.9 million for the nine months ended September 30, 2017. The increase was due to an increased number of well service rigs, to an average of 136 rigs from an average of 78 rigs, providing workover rig services, which is primarily related to the ESCO Acquisition and accounted for $42.6 million, or 39% of the segment increase. The increase in workover rig services included a 63% increase in total rig hours to 224,600 from 137,500 for the nine months ended September 30, 2018 compared to the nine months ended September 30, 2017. In addition, our wireline business accounted for $61.5 million of the increase in revenues, as the majority of this business commenced operation in the Permian Basin during 2018.
Processing Solutions. Processing Solutions revenues for the nine months ended September 30, 2018 increased $5.0 million, or 85%, to $10.9 million from $5.9 million for the nine months ended September 30, 2017. The increase was primarily attributable to additional compressors, tanks, and generator rentals and the additional mobilization revenue associated with such rentals.
Cost of services (excluding depreciation and amortization shown separately). Cost of services for the nine months ended September 30, 2018 increased $89.5 million, or 107%, to $172.8 million from $83.3 million for the nine months ended September 30, 2017. As a percentage of revenue, cost of services was 79% and 80% for the nine months ended September 30, 2018 and 2017, respectively. The increase in cost of services by segment was as follows:
Well Services. Well Services cost of services for the nine months ended September 30, 2018 increased $86.6 million, or 107%, to $167.7 million from $81.1 million for the nine months ended September 30, 2017. The increase was primarily attributable to an increase in expenses due to the expansion of the Company’s activities; notably employee costs and repair and maintenance costs.
Processing Solutions. Processing Solutions cost of services for the nine months ended September 30, 2018 increased $2.9 million, or 132%, to $5.1 million from $2.2 million for the nine months ended September 30, 2017. The increase was primarily attributable to increases in new equipment rentals and the mobilization costs incurred in connection with such rental corresponding to additional revenues.


General & Administrative. General and administrative expenses for the ninesix months ended SeptemberJune 30, 20182019 decreased $3.2$1.3 million, or 13%9%, to $20.8$13.5 million from $24.0$14.8 million for the ninesix months ended SeptemberJune 30, 2017. The decrease in general and administrative expenses by segment was as follows:
Well Services and other.  Well Services general and administrative expenses for the nine months ended September 30, 2018 decreased $3.2 million, or 15%, to $18.7 million from $21.9 million for the nine months ended September 30, 2017.2018. The decrease was primarily attributable to a decrease in expenses due to the expenses foremployee-related costs and professional and other costs associated with the Offering during 2017.
Processing Solutions. Processing Solutions general and administrative expenses remained constant at $2.1 million for the nine months ended September 30, 2018 and 2017.fees.
Depreciation and Amortization.Depreciation and amortization for the ninesix months ended SeptemberJune 30, 20182019 increased $8.9$3.7 million, or 76%28%, to $20.6$16.8 million from $11.7$13.1 million for the ninesix months ended SeptemberJune 30, 2017.2018. The increase in depreciation and amortization expense by segment was as follows:
Well Services and other.  Well Services depreciation and amortization expense for the nine months ended September 30, 2018 increased $8.6 million, or 79%, to $19.5 million from $10.9 million for the nine months ended September 30, 2017. The increase was primarilyis attributable to fixed assets that were put in placeadded during 2017 and the nine monthsyear ended September 30, 2018, including those acquired as part of the ESCO Acquisition.
Processing Solutions. Processing Solutions depreciation expense was $1.1 million for the nine months ended September 30, 2018 compared to $0.8 million for the nine months ended September 30, 2017.December 31, 2018.
Impairment of goodwill.  Impairment of goodwill for the ninesix months ended SeptemberJune 30, 2018 was $9.0 million compared to no impairment for the ninesix months ended SeptemberJune 30, 2017.2019. During the ninesix months ended SeptemberJune 30, 2018 we identified that there was a sustained decrease in the Company’s stock price, which we identified as a triggering event that precipitated the need to perform a goodwill impairment test. The results of the quantitative impairment test yielded a fair value of the Well ServicesHigh Specification Rig reporting unit that was below the carrying value of the Well Services reporting unit as of March 31, 2018 by an amount in excess of the carrying value of goodwill. Therefore we recorded an impairment charge based on the excess of our carrying amount over the fair value.$9.0 million was recorded. Please see Note 75 — Goodwill and Intangible Assets to the unaudited interim condensed consolidated financial statements for further details.statements.
Interest Expense, net. Interest expense, net for the ninesix months ended SeptemberJune 30, 20182019 decreased $4.1$2.3 million, or 69%256%, to $1.8$3.2 million from $5.9$0.9 million for the ninesix months ended SeptemberJune 30, 2017.2018. The decreaseincrease to interest expense, net was attributable to the repayment of the Bridge Loan during 2017 by issuing Class A Common Stockborrowings on our Encina Master Financing Agreement, which was entered into in June 2018, and Ranger Units (and corresponding number of shares ofincreased borrowings under our Class B Common Stock) to the Bridge Loan Lenders during the nine months ended September 30, 2018 compared to the nine months ended September 30, 2017.Credit Facility.
Note Regarding Non‑GAAP Financial Measure
Adjusted EBITDA is not a financial measure determined in accordance with GAAP. We define Adjusted EBITDA as net income (loss) before interest expense, net, income tax provision (benefit), depreciation and amortization, equity‑based compensation, IPO and acquisition‑related and severance costs, impairment of goodwill, gain or loss on sale of assets and certain other items that we do not view as indicative of our ongoing performance.
We believe Adjusted EBITDA is a useful performance measure because it allows for an effective evaluation of our operating performance when compared to our peers, without regard to our financing methods or capital structure. We exclude the items listed above from net income (loss) in arriving at Adjusted EBITDA because these amounts can vary substantially 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 loss determined in accordance with GAAP. 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 reflected in Adjusted EBITDA. Our presentation of Adjusted EBITDA should not be construed as an indication that our results will be unaffected by the items excluded from Adjusted EBITDA. Our computations of Adjusted EBITDA may not be identical to other similarly titled measures of other companies. The following table presents reconciliations of net income (loss) to Adjusted EBITDA, our most directly comparable financial measure calculated and presented in accordance with GAAP.


Three Months Ended SeptemberJune 30, 20182019 compared to Three Months Ended SeptemberJune 30, 20172018
 Three Months Ended September 30, 2018 Three Months Ended
   Well Processing   June 30, 2019
 Other Services Solutions Total High Specification Rigs Completion and Other Services Processing Solutions Other Total
 (in millions) (in millions)
Net income (loss) $(8.2) $11.0
 $1.2
 $4.0
 $(0.4) $8.4
 $2.5
 $(8.7) $1.8
Interest expense, net 0.9
 —
 —
 0.9
Tax expense 0.4
 (0.9) —
 (0.5)
Interest expense —
 —
 —
 1.7
 1.7
Tax expense (benefit) —
 —
 —
 0.3
 0.3
Depreciation and amortization 0.2
 6.8
 0.5
 7.5
 4.8
 2.9
 0.5
 0.2
 8.4
Equity based compensation 1.6
 (1.0) —
 0.6
 —
 —
 —
 0.9
 0.9
IPO, Acquisition, and severance costs —
 0.3
 —
 0.3
 —
 —
 —
 —
 —
Gain on property, plant and equipment —
 (0.2) —
 (0.2)
(Gain) loss on property, plant and equipment —
 —
 —
 (0.1) (0.1)
Adjusted EBITDA $(5.1) $16.0
 $1.7
 $12.6
 $4.4
 $11.3
 $3.0
 $(5.7) $13.0
 Three Months Ended September 30, 2017 Three Months Ended
   Well Processing   June 30, 2018
 Other Services Solutions Total High Specification Rigs Completion and Other Services Processing Solutions Other Total
 (in millions) (in millions)
Net income (loss) $—
 $(9.9) $0.4
 $(9.5) $1.4
 $5.9
 $1.7
 $(10.2) $(1.2)
Interest expense, net —
 4.3
 —
 4.3
Tax expense —
 0.4
 —
 0.4
Interest expense —
 —
 —
 0.5
 0.5
Tax expense (benefit) —
 —
 —
 1.7
 1.7
Depreciation and amortization —
 3.8
 0.3
 4.1
 4.6
 1.8
 0.4
 0.2
 7.0
Equity based compensation —
 0.1
 0.1
 0.2
 —
 —
 —
 0.8
 0.8
IPO, Acquisition, and severance costs —
 3.5
 —
 3.5
 0.3
 —
 —
 0.3
 0.6
Gain on property, plant and equipment —
 —
 —
 —
(Gain) loss on property, plant and equipment 0.2
 —
 —
 —
 0.2
Adjusted EBITDA $—
 $2.2
 $0.8
 $3.0
 $6.5
 $7.7
 $2.1
 $(6.7) $9.6
 Change $
   Well Processing   Change $
 Other Services Solutions Total High Specification Rigs Completion and Other Services Processing Solutions Other Total
 (in millions) (in millions)
Net income (loss) $(8.2) $20.9
 $0.8
 $13.5
 $(1.8) $2.5
 $0.8
 $1.5
 $3.0
Interest expense, net 0.9
 (4.3) —
 (3.4)
Tax expense 0.4
 (1.3) —
 (0.9)
Interest expense —
 —
 —
 1.2
 1.2
Tax expense (benefit) —
 —
 —
 (1.4) (1.4)
Depreciation and amortization 0.2
 3.0
 0.2
 3.4
 0.2
 1.1
 0.1
 —
 1.4
Equity based compensation 1.6
 (1.1) (0.1) 0.4
 —
 —
 —
 0.1
 0.1
IPO, Acquisition, and severance costs —
 (3.2) —
 (3.2) (0.3) —
 —
 (0.3) (0.6)
Gain on property, plant and equipment —
 (0.2) —
 (0.2)
(Gain) loss on property, plant and equipment (0.2) —
 —
 (0.1) (0.3)
Adjusted EBITDA $(5.1) $13.8
 $0.9
 $9.6
 $(2.1) $3.6
 $0.9
 $1.0
 $3.4
Adjusted EBITDA for the three months ended SeptemberJune 30, 20182019 increased $9.6$3.4 million to $12.6$13.0 million from $3.0$9.6 million for the three months ended SeptemberJune 30, 2017.2018. The increasechange by segment was as follows:
Well ServicesHigh Specification Rigs. Well ServicesHigh Specification Rigs Adjusted EBITDA for the three months ended SeptemberJune 30, 2018 increased $13.82019 decreased $2.1 million to $16.0$4.4 million from $2.2$6.5 million for the three months ended SeptemberJune 30, 2017,2018, primarily due to significant increaseddecreased revenues of $39.1$6.5 million, partially offset by a corresponding decrease in cost of services of $4.9 million.
Completion and Other Services. Completion and Other Services Adjusted EBITDA increased $3.6 million to $11.3 million from $7.7 million for the three months ended June 30, 2018, due to an increase in revenues of $16.8 million partially offset by a corresponding increase in cost of services of $28.7 million, as well as a decrease in IPO and acquisition related and severance costs of $3.2 million offset partially by an increase in the depreciation and amortization expense of $3.0 million.
Processing Solutions. Processing Solutions Adjusted EBITDA for the three months ended September 30, 2018 increased $0.9 million to $1.7 million from $0.8 million for the three months ended September 30, 2017 due primarily to an increase in net income of $0.8 million.
Other. Other Adjusted EBITDA for the three months ended September 30, 2018 is a loss of $5.1 million due primarily to general and administrative expense of $4.5 million related to compensation and benefits, professional fees and other general expenses. The balances included in Other reflect the reorganization and other general and administrative costs not directly


attributable to Well Services or Processing Solutions. Prior to the Offering and subsequent reorganization the Well Services and Processing Solutions were run as separate companies and therefore did not include Other for the three months ended September 30, 2017.
Nine Months Ended September 30, 2018 compared to Nine Months Ended September 30, 2017
  Nine Months Ended September 30, 2018
    Well Processing  
  Other Services Solutions Total
  (in millions)
Net income (loss) $(21.3) $11.1
 $2.7
 $(7.5)
Interest expense, net 1.8
 —
 —
 1.8
Tax expense 0.3
 —
 —
 0.3
Depreciation and amortization 0.6
 18.9
 1.1
 20.6
Equity based compensation 1.6
 —
 —
 1.6
IPO, Acquisition, and severance costs 0.3
 0.6
 —
 0.9
Impairment of goodwill —
 9.0
 —
 9.0
Loss on property, plant and equipment —
 0.7
 —
 0.7
Adjusted EBITDA $(16.7) $40.3
 $3.8
 $27.4
  Nine Months Ended September 30, 2017
    Well Processing  
  Other Services Solutions Total
  (in millions)
Net income (loss) $—
 $(22.3) $0.8
 $(21.5)
Interest expense, net —
 5.9
 —
 5.9
Tax expense —
 0.4
 —
 0.4
Depreciation and amortization —
 10.9
 0.8
 11.7
Equity based compensation —
 0.8
 0.1
 0.9
IPO, Acquisition, and severance costs —
 10.2
 —
 10.2
Impairment of goodwill —
 —
 —
 —
Loss on property, plant and equipment —
 —
 —
 —
Adjusted EBITDA $—
 $5.9
 $1.7
 $7.6
  Change $
    Well Processing  
  Other Services Solutions Total
  (in millions)
Net income (loss) $(21.3) $33.4
 $1.9
 $14.0
Interest expense, net 1.8
 (5.9) —
 (4.1)
Tax expense 0.3
 (0.4) —
 (0.1)
Depreciation and amortization 0.6
 8.0
 0.3
 8.9
Equity based compensation 1.6
 (0.8) (0.1) 0.7
IPO, Acquisition, and severance costs 0.3
 (9.6) —
 (9.3)
Impairment of goodwill —
 9.0
 —
 9.0
Loss on property, plant and equipment —
 0.7
 —
 0.7
Adjusted EBITDA $(16.7) $34.4
 $2.1
 $19.8
Adjusted EBITDA for the nine months ended September 30, 2018 increased $19.8 million to $27.4 million from $7.6 million for the nine months ended September 30, 2017. The increase by segment was as follows:
Well Services. Well Services Adjusted EBITDA for the nine months ended September 30, 2018 increased $34.4 million to $40.3 million from $5.9 million for the nine months ended September 30, 2017 due mainly to significant increased revenues of $109.0 million offset by a corresponding increase in cost of services of $86.6$13.2 million.


Processing Solutions. Processing Solutions Adjusted EBITDA for the ninethree months ended SeptemberJune 30, 20182019 increased $2.1$0.9 million to $3.8$3.0 million from $1.7$2.1 million for the ninethree months ended SeptemberJune 30, 20172018, due primarily to an increase in net incomerevenue of $1.9$0.9 million.
Other. Other Adjusted EBITDA for the ninethree months ended SeptemberJune 30, 2018 is2019 increased $1.0 million to a loss of $16.7$5.7 million due primarily to general and administrative expensefrom a loss of $18.5$6.7 million related to compensation and benefits, professional fees, and other general expenses.for the three months ended June 30, 2018. The balances included in Other reflect the reorganization and other general and administrative costs not directly attributable to WellHigh Specification Rigs, Completion and Other Services or Processing Solutions. PriorThe decrease is primarily due to a reduction in the OfferingCompany’s general and subsequent reorganizationadministrative costs.
Six Months Ended June 30, 2019 compared to Six Months Ended June 30, 2018
  Six Months Ended
  June 30, 2019
  High Specification Rigs Completion and Other Services Processing Solutions Other Total
  (in millions)
Net income (loss) $(0.9) $19.3
 $4.8
 $(17.8) $5.4
Interest expense, net —
 —
 —
 3.2
 3.2
Tax expense —
 —
 —
 0.6
 0.6
Depreciation and amortization 9.6
 5.7
 1.0
 0.5
 16.8
Equity based compensation —
 —
 —
 1.5
 1.5
IPO, Acquisition, and severance costs —
 —
 —
 —
 —
Impairment of goodwill —
 —
 —
 —
 —
(Gain) loss on property, plant and equipment —
 —
 —
 (0.3) (0.3)
Adjusted EBITDA $8.7
 $25.0
 $5.8
 $(12.3) $27.2
  Six Months Ended
  June 30, 2018
  High Specification Rigs Completion and Other Services Processing Solutions Other Total
  (in millions)
Net income (loss) $(6.8) $9.2
 $3.0
 $(16.9) $(11.5)
Interest expense, net —
 —
 —
 0.9
 0.9
Tax expense —
 —
 —
 0.8
 0.8
Depreciation and amortization 8.6
 3.5
 0.6
 0.4
 13.1
Equity based compensation —
 —
 —
 1.0
 1.0
IPO, Acquisition, and severance costs 0.3
 —
 —
 0.3
 0.6
Impairment of goodwill 9.0
 —
 —
 —
 9.0
(Gain) loss on property, plant and equipment 0.9
 —
 —
 —
 0.9
Adjusted EBITDA $12.0
 $12.7
 $3.6
 $(13.5) $14.8
  Change $
  High Specification Rigs Completion and Other Services Processing Solutions Other Total
  (in millions)
Net income (loss) $5.9
 $10.1
 $1.8
 $(0.9) $16.9
Interest expense, net —
 —
 —
 2.3
 2.3
Tax expense —
 —
 —
 (0.2) (0.2)
Depreciation and amortization 1.0
 2.2
 0.4
 0.1
 3.7
Equity based compensation —
 —
 —
 0.5
 0.5
IPO, Acquisition, and severance costs (0.3) —
 —
 (0.3) (0.6)
Impairment of goodwill (9.0) —
 —
 —
 (9.0)
(Gain) loss on property, plant and equipment (0.9) —
 —
 (0.3) (1.2)
Adjusted EBITDA $(3.3) $12.3
 $2.2
 $1.2
 $12.4


Adjusted EBITDA for the Wellsix months ended June 30, 2019 increased $12.4 million to $27.2 million from $14.8 million for the six months ended June 30, 2018. The change by segment was as follows:
High Specification Rigs. High Specification Rigs Adjusted EBITDA for the six months ended June 30, 2019 decreased $3.3 million to $8.7 million from $12.0 million for the six months ended June 30, 2018, primarily due to decreased revenues of $11.1 million, partially offset by a corresponding decrease in cost of services of $9.0 million.
Completion and Other Services. Completion and Other Services andAdjusted EBITDA increased $12.3 million to $25.0 million from $12.7 million for the six months ended June 30, 2018, due to an increase in revenues of $45.0 million partially offset by a corresponding increase in cost of services of $32.7 million.
Processing Solutions. Processing Solutions were run as separate companies and therefore did not include OtherAdjusted EBITDA for the ninesix months ended SeptemberJune 30, 2017.  2019 increased $2.2 million to $5.8 million from $3.6 million for the six months ended June 30, 2018, due to an increase in revenue of $3.0 million, partially offset by a corresponding increase in cost of services of $0.8 million.
Other. Other Adjusted EBITDA for the six months ended June 30, 2019 increased $1.2 million to a loss of $12.3 million from a loss of $13.5 million for the six months ended June 30, 2018. The balances included in Other reflect other general and administrative costs not directly attributable to High Specification Rigs, Completion and Other Services or Processing Solutions. The decrease is primarily due to a reduction in the Company’s general and administrative costs.
Liquidity and Capital Resources
Overview
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 are cash generated from operations and borrowings under our Credit Facility and Financing Agreement.Agreement and cash generated from operations. We strive to maintain financial flexibility and proactively monitor potential capital sources to meet our investment and target liquidity requirements and to permit us to manage the cyclicality associated with our business.
As of SeptemberJune 30, 2018,2019, we had cash on hand of approximately $2.0 million. Our$1.7 million, operating cash on hand, expected cash flow from operations,flows of $14.2 million and availability under our Credit Facility ($21.7 million available as of September 30, 2018), and the additional borrowing capacity under the Financing Agreement (approximately $18.0 million available as of September 30, 2018) is expected$14.0 million. We expect to behave sufficient funds to meet the Company’s liquidity requirements for at least the next 12 months.
Cash Flows
The following table presents our cash flows for the periods indicated:
  Nine Months Ended September 30,    
   Change
  2018 2017 $ %
  (in millions)
Cash flows provided by (used in) operating activities $24.9
 $(7.6) $32.5
 428 %
Cash flows used in investing activities (56.1) (64.1) 8.0
 (12)%
Cash flows provided by financing activities 27.9
 89.1
 (61.2) (69)%
Net change in cash $(3.3) $17.4
 $(20.7) (119)%
  Six Months Ended    
  June 30, 2019 Change
  2019 2018 $ %
  (in millions)
Cash Flows from Operating Activities $14.2
 $12.1
 $2.1
 17 %
Cash Flows from Investing Activities (15.5) (34.5) 19.0
 (55)%
Cash Flows from Financing Activities 0.4
 27.6
 (27.2) (99)%
Net change in cash $(0.9) $5.2
 $(6.1) (117)%
Operating Activities
Net cash provided by operating activities increased $32.5$2.1 million to $24.9$14.2 million for the ninesix months ended SeptemberJune 30, 20182019 compared to $7.6$12.1 million usedof cash generated for the ninesix months ended SeptemberJune 30, 2017.2018. The change in cash flows used inprovided by operating activities is primarily attributable to a decreasean increase in gross margin for the net loss during the current periodsix months ended June 30, 2019 compared to the prior period, reduced by an increase in depreciation and amortization of $8.9 million and the impairment to goodwill of $9.0 million.six months ended June 30, 2018. The use of working capital cash for the ninesix months ended SeptemberJune 30, 20182019 increased to $1.2$11.5 million as compared to the $4.1$0.5 million deficit during the ninesix months ended SeptemberJune 30, 2017.2018.
Investing Activities
Net cash used in investing activities decreased $8.0$19.0 million to $56.1$15.5 million for the ninesix months ended SeptemberJune 30, 20182019 compared to $64.1$34.5 million for the ninesix months ended SeptemberJune 30, 2017.2018. The changedecrease in cash flows used in investing activities is primarily attributable to the ESCO Acquisitionfixed assets acquired during the nineyear ended December 31, 2018, which includes the MVCI Acquisition that took place during the six months ended SeptemberJune 30, 2017, which2018. The decreases in the use of cash was partially offset by purchasesa reduction in cash proceeds from the sale of property plant and equipment.


Financing Activities
Net cash provided by financing activities decreased $61.2$27.2 million to $27.9$0.4 million for the ninesix months ended SeptemberJune 30, 20182019 compared to $89.1$27.6 million for the ninesix months ended SeptemberJune 30, 2017.2018. The changedecrease in cash flows provided by financing activities is primarily attributable to proceeds from the Offeringdecreased borrowings under our line of $80.8 million and borrowings from related parties of $21.0 million during the nine months ended September 30, 2017. Additionally, there was an increase incredit, increased payments on long-term debt of $13.6 million during the nine months ended September 30, 2018. This wasCredit Facility and the Financing Agreement, partially offset by borrowings under the our Credit Facilitydecreased payments of $41.8 million and borrowing under long-term debt of $21.3 million.


financing lease obligations.
Supplemental Disclosures
We added assets worth $5.3of $2.3 million that arewere non-cash additions in the ninesix months ended SeptemberJune 30, 2018.2019 and purchased $0.8 million in finance leased assets. In addition, as of January 1, 2019, we also purchased $10.4added ROU assets and liabilities of $8.3 million in assets via capital lease financing.related to the adoption of ASC 842. See Note 2 — Summary of Significant Accounting Policies and Note 7 — Leases to the unaudited interim condensed consolidated financial statements for more information for details of the adoption of ASC 842. Also, we settled a $3.0 million liability by issuing Class A Common Stock to a related party.
Working Capital
Our working capital, which we define as total current assets less total current liabilities, totaled $11.9$15.2 million (deficit) and $3.2$2.2 million (deficit) as of SeptemberJune 30, 20182019 and December 31, 2017,2018, respectively.  
Our Debt Agreements
ESCO Notes Payable
In connection with the Offering and the ESCO Acquisition we issued $7.0 million of seller’s notes as partial consideration for the ESCO Acquisition. These notes includeincluded a note for $1.2 million, which was paid in August 2018 and a note for $5.8 million due on February 16, 2019. Both of these notes bear interest at 5.0% payable quarterly until their respective maturity dates.
InDuring the year ended December 31, 2018, we provided notice to ESCO Leasing, LLC that we are seeking to be indemnified for breach of our contract. We exercised our right to stop payments of the remaining principal balance of $5.8 million on the Seller's Notes and any unpaid interest, pending resolution of certain indemnification claims.
Credit Facility
On August 16, 2017, in connection with the Offering,offering, we entered into a new credit agreement providing for our $50.0 million Credit Facility. The Credit Facility is subject to a borrowing base that is calculated based upon a percentage of the value of our eligible accounts receivable less certain reserves. The borrowing base is calculated on a monthly basis pursuant to a borrowing base certificate delivered by us to the Administrative Agent. The Credit Facility is used for capital expenditures and permitted acquisitions, to provide for working capital requirements and for other general corporate purposes. The Credit Facility is secured by certain of our assets and contains various affirmative and negative covenants and restrictive provisions. We had approximately $40.2$40.3 million of borrowing capacity with $21.7$14.0 million available under the Credit Facility as of SeptemberJune 30, 2018.2019.
The Credit Facility permits extensions of credit up to the lesser of $50.0 million and a borrowing base that is determined by calculating the amount equal to the sum of (i) 85% of the Eligible Accounts (as defined in the Credit Facility), less the amount, if any, of the Dilution Reserve (as defined in the Credit Facility), minus (ii) the aggregate amount of Reserves (as defined in the Credit Facility), if any, established by the Administrative Agent from time to time pursuant to the Credit Facility. The borrowing base is calculated on a monthly basis pursuant to a borrowing base certificate delivered by the Borrower to the Administrative Agent. 
Borrowings under the Credit Facility bear interest, at our election, at either the (a) one-, two-, three- or six-month LIBOR or (b) the greatest of (i) the federal funds rate plus ½%, (ii) the one-month LIBOR plus 1% and (iii) the Base Rate, in each case plus an applicable margin, and interest shall be payable monthly in arrears. The applicable margin for LIBOR loans ranges from 1.50% to 2.00% and the applicable margin for Base Rate loans ranges from 0.50% to 1.00%, in each case, depending on our average excess availability under the Credit Facility. The applicable margin for LIBOR loans is 1.50%1.75% and the applicable margin for Base Rate loans is 0.50%0.75% until SeptemberJune 30, 2018.2019. During the continuance of a bankruptcy event of default, automatically and during the continuance of any other default, upon the Administrative Agent’s or the required lenders’ election, all outstanding amounts under the Credit Facility bears interest at 2.00% plus the otherwise applicable interest rate. The Credit Facility is scheduled to mature on the fifth anniversary of the consummation of the Offering (August 16, 2022). As of SeptemberJune 30, 20182019 the Credit Facility had an interest rate of 5.75%4.7%.
In addition, the Credit Facility restricts our ability to make distributions on, or redeem or repurchase, our equity interests, except for certain distributions, including distributions of cash so long as, both at the time of the distribution and after giving effect to the distribution, no default exists under the Credit Facility and either (a) excess availability at all times during the preceding 90 consecutive days, on a pro forma basis and after giving effect to such distribution, is not less than the greater of (1) 22.5% of the lesser of (A) the maximum revolver amount and (B) the then-effective borrowing base and (2) $10.0 million or (b) if our fixed charge coverage ratio is at least 1.0x on a pro forma basis, excess availability at all times during the preceding 90 consecutive


days, on a pro forma basis and after giving effect to such distribution, is not less than the greater of (1) 17.5% of the lesser of (A) the maximum revolver amount and (B) the then-effective borrowing base and (2) $7.0 million. If the foregoing threshold under clause (b) is met, we may not make such distributions (but may make certain other distributions, including under clause (a) above) prior to the earlier of the date that is (a) 12 months from closing or (b) the date that our fixed charge coverage ratio is at least 1.0x for two consecutive quarters. Our Credit Facility generally permits us to make distributions required under the TRA, but a ‘‘Change of Control’’ under the TRA constitutes an event of default under our Credit Facility, and our Credit Facility does not permit us to make payments under the TRA upon acceleration of our obligations thereunder unless no event of default exists or would result therefrom and we have been in compliance with the fixed charge coverage ratio for the most recent 12-month period on a pro forma basis. Our Credit Facility also requires us to maintain a fixed charge coverage ratio of at least 1.0x if our liquidity is less than $10.0 million until our liquidity is at least $10.0 million for 30 consecutive days. We are not subject to a fixed charge coverage ratio if we have no drawings under the Credit Facility and have at least $20.0 million of qualified cash.
The Credit Facility contains events of default customary for facilities of this nature, including, but not limited, to:
events of default resulting from our failure or the failure of any guarantors to comply with covenants and financial ratios;


the occurrence of a change of control;
the institution of insolvency or similar proceedings against us or any guarantor; and
the occurrence of a default under any other material indebtedness we 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 Credit Facility, the lenders are able to declare any outstanding principal of our Credit Facility debt, together with accrued and unpaid interest, to be immediately due and payable and exercise other remedies.
Encina Master Financing and Security Agreement (“Financing Agreement”)
On June 22, 2018, the Company entered into thea Master Financing Agreement.and Security Agreement with Encina Equipment Finance SPV, LLC (the “Lender”). The amount available to be provided by the Lender to the Company under the Financing Agreement was contemplated to be not less than $35.0 million, however wasand not to exceed $40.0 million. The first financing was required to be in an amount up to $22.0 million, which was used by the Company to acquire certain capital equipment. Subsequent financings could be made, as agreed byto the first financing, the Company and Lender. Amounts outstandingborrowed an additional $17.8 million, net of expenses, under the Financing Agreement. We utilized the additional net proceeds to acquire certain capital equipment. The Financing Agreement are payable ratably over 48 months through maturity of July 2022. is secured by a lien on certain high specification rig assets. At June 30, 2019, the aggregate principal balance outstanding was $32.7 million under the Financing Agreement.
Borrowings under the Financing Agreement bear interest at a rate per annum equal to the sum of 8.0% plus the LIBOR,London Interbank Offered Rate (“LIBOR”), which was 2.2%2.4% as of SeptemberJune 30, 2018.2019. The Financing Agreement requires that the Company maintain leverage ratios of 5.002.50 to 1.00 as of SeptemberJune 30, 2018, 3.50 to 1.00 as of December 31, 20182019 and 2.50 to 1.00 for periods thereafter. As of September 30, 2018The Company was in compliance with the covenants under the Financing Agreement had an interest rateas of 10.1%.
Contractual and Commercial CommitmentsJune 30, 2019.
The following table summarizes our contractual obligationsCompany capitalized fees of $0.9 million associated with the Financing Agreement, which are included on the unaudited interim condensed consolidated balance sheets as a discount to the long term debt, and commercial commitmentswill be amortized through maturity. Unamortized debt issuance costs as of SeptemberJune 30, 2018:2019 approximated $0.7 million.
    Less than     More than
  Total 1 year 1 - 3 years 3 - 5 years 5 years
  (in millions)
Long-term debt obligations $44.1
 $11.3
 $32.8
 $—
 $—
Capital lease obligations 10.4
 3.9
 6.5
 —
 —
Operating lease obligations 12.1
 3.2
 4.3
 1.0
 3.6
Purchase obligations for rigs 16.6
 16.6
 —
 —
 —
Total $83.2
 $35.0
 $43.6
 $1.0
 $3.6
Tax Receivable Agreement
With respect to obligations we expect to incur under our TRA (except in cases where we elect to terminate the TRA early, the TRA is terminated early due to certain mergers, asset sales, other forms of business combination or other changes of control or we have available cash but fail to make payments when due), generally we may elect to defer payments due under the TRA if we do not have available cash to satisfy our payment obligations under the TRA or if our contractual obligations limit our ability to make these payments. Any such deferred payments under the TRA generally will accrue interest. In certain cases, payments under the TRA may be accelerated and/or significantly exceed the actual benefits, if any, we realize in respect of the tax attributes subject to the TRA. We intend to account for any amounts payable under the TRA in accordance with ASC 450, Contingencies. Further, we intend to account for the effect of increases in tax basis and payments for such increases under the TRA arising from future redemptions as follows:
when future sales or redemptions occur, we will record a deferred tax liability for the gross amount of the income tax effect along with an offset of 85% of this liability as payable under the TRA; the remaining difference between the deferred tax liability and tax receivable agreement liability will be recorded as additional paid‑in capital; and
to the extent we have recorded a deferred tax asset for an increase in tax basis to which a benefit is no longer expected to be realized due to lower future taxable income, we will reduce the deferred tax asset with a valuation allowance.


Critical Accounting Policies and Estimates
Our significant accounting policies are discussed in our Annual Report. Except as discussed below, our critical accounting estimatesReport and policies have not materially changed since December 31, 2017. Effective January 1, 2018,2018.
Recent Accounting Pronouncements
In February 2016, the Company adopted ASC 606 – RevenueFASB issued Accounting Standards Update (“ASU”) 2016‑02, Leases, amending the current accounting for leases. Under the new provisions, all lessees, except those with terms of 12-months or less, will report a right‑of‑use (“ROU”) asset and a liability for the obligation to make payments for all leases and will be categorized as either a financing lease or an operating lease. We determine if an arrangement is a lease and the category of each lease at inception.
ROU assets represent our right to use an underlying asset for the lease term and lease liabilities represent our obligation to make lease payments arising from Contracts with Customers, using the modified retrospective method. This standard applies to all contracts with customers, except for contracts thatlease, discounted at our annual incremental borrowing rate (“IBR”). ROU assets and liabilities are withinrecognized at the scopecommencement date based on the present value of other standards, such as leases, insurance, collaborative arrangementslease payments over the lease term. Variable lease payments are excluded from the ROU asset and financial instruments. Under ASC 606, an entity recognizes revenue when it transfers control oflease liabilities and are recognized in the promised goods or services to its customer,period in an amount that reflects the consideration which the entity expects to receive in exchangeobligation for those goodspayments are incurred. For certain leases, where variable lease payments are incurred and relate primarily to common area maintenance costs, in substance fixed payments are included in the ROU asset and lease liability. For those leases that do not provide an implicit rate, we use our IBR based on the information available at the lease commencement date in determining the present value of lease payments. ROU assets also include any lease payments made and exclude lease incentives. Our lease terms do not include options to extend or services. If control transfersterminate the lease, as management does not consider them reasonably certain to the customer over time, an entity selects a method to measure progress that is consistent with the objective of depicting its performance.exercise. See Note 2 — Summary of Significant Accounting Policies and Note 37 — Revenue from Contracts with CustomersLeases to the unaudited interim condensed consolidated financial statements for more information.


The Company performs its annual goodwill impairment test at the beginning of the fourth quarter of each fiscal year. The Company’s goodwill at the time of the annual impairment test of approximately $9.0 million was all attributable to the Company’s Well Services segment and the majority of such goodwill (approximately $7.4 million) was generated in connection with the ESCO Acquisition, which closed in connection with the Offering on August 16, 2017, which was within 45 days of the annual impairment test date. The Company evaluated the relevant events and circumstances at that point in time and concluded that it was not more likely than not that the fair value of the Well Services reporting unit was less than its carrying amount.
Midway through the fourth quarter of 2017, the Company’s stock price started decreasing and remained stagnant through December 31, 2017. The Company evaluated whether a triggering event had occurred as of December 31, 2017; however, macroeconomic conditions had improved, the oil and gas industry and related market conditions had improved (steady increase in oil pricing through December 31, 2017 and into the first quarter of 2018) and the Company’s overall financial and operating performance had improved, as there was increased revenue, profitability, utilization and rates per hour during the fourth quarter of 2017. As a result, the Company concluded there was no triggering event at December 31, 2017.
During the first quarter of 2018 the Company identified there was a sustained decrease in the Company’s stock price, which the Company identified as a triggering event that precipitated the need to perform a goodwill impairment test. The Company elected to bypass the qualitative assessment and performed step one of the annual goodwill impairment test at March 31, 2018. The results of the quantitative impairment test yielded a fair value of the Well Services reporting unit that was below the carrying value of the Well Services reporting unit as of March 31, 2018 by an amount in excess of the carrying value of goodwill. Accordingly, all of the Company’s historical goodwill was impaired at March 31, 2018.
Due to the triggering event and goodwill impairment charged at March 31, 2018, the Company assessed whether the long-lived assets, which consist of property, plant and equipment and intangible assets, were impaired by comparing the carrying value of its long-lived assets to the estimating future undiscounted cash flows of their reporting units and concluded they were not impaired.
Recent Accounting Pronouncements
For information regarding new accounting policies or updates to existing accounting policies as a result of new accounting pronouncements, please refer to Note 2 — Summary of Significant Accounting Policies to the unaudited interim condensed consolidated financial statements of this Quarterly Report.
Off‑Balance Sheet Arrangements
We currently have no material off‑balance sheet arrangements.
Jumpstart Our Business Act of 2012
We are an “emerging growth company” as defined in the JOBS Act. We will remain an emerging growth company until the earlier of (1) the last day of our fiscal year (a) following the fifth anniversary of the completion of the Offering, (b) in which we have total annual gross revenue of at least $1.07 billion, or (c) in which we are deemed to be a large accelerated filer, which means the market value of our common stock that is held by non-affiliates exceeds $700.0 million as of the last business day of our most recently completed second fiscal quarter, andor (2) the date on which we have issued more than $1.0 billion in non-convertible debt securities during the prior three-year period. An emerging growth company may take advantage of specified reduced reporting and other burdens that are otherwise applicable generally to public companies. We have irrevocably opted out of the extended transition period and, as a result, we will adopt new or revised accounting standards on the relevant dates on which adoption of such standards is required for other public companies.


CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS
The information in this Quarterly Report includes “forward‑looking statements” within the meaning of Section 27A of the Securities Act, as amended and Section 21E of the Exchange Act of 1934 (the "Exchange Act"“Exchange Act”), as amended. 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 included in our Annual Report. These forward‑looking statements are based on management’s current belief, 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;
our ability to sustain and improve our utilization, revenues 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;
marketing of oil and natural gas;
business or asset acquisitions, including the ESCO Acquisition;acquisitions;
general economic conditions;
credit markets;
our ability to successfully develop our research and technology capabilities and implement technological developments and enhancements;
uncertainty regarding our future operating results; and
plans, objectives, expectations and intentions contained in this 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, the risks described under “Risk Factors” in our Annual Report previously filed. Should one or more of the risks or uncertainties described occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward‑looking statements.
All forward‑looking statements, expressed or implied, included in this Quarterly Report are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward‑looking statements that we or persons acting on our behalf may issue. Except as otherwise required by applicable law, we disclaim any duty to update any forward‑looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this Quarterly Report.



Item 3. Quantitative and Qualitative DisclosureDisclosures about Market Risks
The demand, pricing and terms for oil and natural 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 level of 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.
Interest Rate Risk
We are exposed to interest rate risk, primarily associated with our Credit Facility and Financing Agreement. For a complete discussion of our interest rate risk, see our Annual Report. As of September 30, 2018, weWe had an aggregate principal amount of $5.8 million outstanding under notes payable from the ESCO Acquisition as of June 30, 2019, with a weighted averagean interest rate of 5.0%, $18.5. As of June 30, 2019, we had $26.3 million outstanding onunder our Credit Facility, with a weighted average interest rate of 4.3% and $21.14.7%. As of June 30, 2019, the aggregate principal balance outstanding was $32.7 million of long-term debtunder the Financing Agreement, with a weighted average interest rate of 10.1%10.5%. A hypothetical 1.0% increase or decrease in the weighted average interest rate would increase or decrease interest expense by approximately $0.4$0.6 million per year. We do not engage in derivative transactions for speculative or trading purposes.
Credit Risk
The majority of our trade receivables have payment terms of 30 days or less. As of SeptemberJune 30, 2018,2019, the top three trade receivable balances represented approximately 16%11%, 11%, and 9%8%, respectively, of total accounts receivable. Within our WellHigh Specification Rig segment, the top three trade receivable balances represented 11%, 9% and 9%, respectively, of total High Specification Rig accounts receivable. Within our Completion and Other Services segment, the top three trade receivable balances represented approximately 16%17%, 12%17%, and 9%13%, respectively, of total WellCompletion and Other Services accounts receivable. Within our Processing Solutions segment, the top three trade receivable balances represented approximately 25%64%, 22%21% and 19%14%, respectively, of total Processing Solutions accounts receivable. We mitigate the associated credit risk by performing credit evaluations and monitoring the payment patterns of our customers.


Commodity Price Risk
The market for our services is indirectly exposed to fluctuations in the prices of oil and natural gas to the extent such fluctuations impact the activity levels of our E&P customers. 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. We do not currently intend to hedge our indirect exposure to commodity price risk.
Item 4. Controls and Procedures
Disclosure Controls and Procedures
As required by Rule 13a‑15(b) under the Exchange Act, we have evaluated, under the supervision and with the participation of management, including our principal executive officerChief Executive Officer and principal financial officer,Chief Financial Officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d‑15(e) under the Exchange Act) as of the end of the period covered by this Quarterly Report. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file or submit under the Exchange Act is accumulated and communicated to management, including our principal executive officerChief Executive Officer and principal financial officer,Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. As of September 30, 2018Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were not effective as a result of the material weakness identified during the year ended December 31, 2017. The material weakness related to the ineffective controls over accounting for non-routine and/or complex transactions.
To address this material weakness, we, along with the oversight of our audit committee, are evaluating our controls over accounting for non-routine and/or complex transactions in an effort to identify additional controls to timely identify misstatements and strengthen our overall control environment as well as continuing to assess our qualified accounting personnel staffing requirements.June 30, 2019.
Changes in Internal Control over Financial Reporting
There were no changes in our internal control over financial reporting during the quarter ended SeptemberJune 30, 20182019 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.


PART II OTHER INFORMATION
ITEMItem 1. Legal Proceedings
Our operations are subject to a variety of risks and disputes normally incident to our business. As a result, we may, at any given time, be a defendant in various legal proceedings and litigation arising in the ordinary course of business. However, we are not currently subject to any material litigation and in the opinion of management, the outcome of any existing matters will not have a material adverse effect on the Company’s consolidated financial position or consolidated results of operations. We maintain insurance policies with insurers in amounts and with coverage and deductibles that we, with the advice of our insurance advisers and brokers, believe are reasonable and prudent. We cannot, however, assure you that this insurance will be adequate to protect us from all material expenses related to potential future claims for personal injury and property damage or that these levels of insurance will be available in the future at economical prices.
Item 1A. Risk Factors.Factors
Factors that could materially adversely affect our business, financial condition, operating results or liquidity and the trading price of our Class A Common Stock are described under “Risk Factors,” included in our Annual Report. This information should be considered carefully, together with other information in this Quarterly Report and other reports and materials we file with the SEC.
Item 2. Unregistered Sales of Securities and Use of Proceeds
(a) Recent Sales of Unregistered Securities; Use of Proceeds from Registered Securities
In connection with the Master Reorganization Agreement, an aggregate of $3.0 million (included within other current liabilities on the accompanying consolidated balance sheet as of December 31, 2018) was settled by the Company and CSL Energy Holdings I, LLC and CSL Energy Holdings II, LLC during the three and six months ended June 30, 2019. At the Company’s discretion the liability was settled with the issuance of 206,897 Class A Common Stock. The Class A Common Stock were issued in a private placement exempt from registration pursuant to Section 4(a)(2) of the Securities Act promulgated thereunder. Refer to Note 1 — Organization and Business Operations for further details.
(c) Purchases of Equity Securities by the Issuer and Affiliated Purchasers
In June 2019, the Company announced that its Board of Directors approved a share repurchase program, authorizing the Company to purchase up to 10% of the Company’s currently outstanding Class A Common Stock held by non-affiliates, not to exceed 580,000 shares or $5 million in aggregate value. Share repurchases may take place from time to time on the open market or through privately negotiated transactions. The duration of the share repurchase program is 12 months and may be accelerated, suspended or discontinued at any time without notice.
The following table provides information with respect to Class A Common Stock purchases made by the Company during the three months ended June 30, 2019.
PeriodTotal number of shares repurchasedAverage price paid per shareTotal number of shares purchased as part of publicly announced plans or programsMaximum number of shares that may yet be purchased under the plans or programs
June 28, 2019 through June 30, 2019—
—
—
—


Item 6. Exhibits
The following exhibits are filed as part of this Quarterly Report.


INDEX TO EXHIBITS
   
Exhibit
Number
 Description
2.12.1††
Master Reorganization Agreement, dated as of August 10, 2017, by and among Ranger Energy Services, Inc., RNGR Energy Services, LLC, Ranger Energy Holdings, LLC, Ranger Energy Holdings II, LLC, Torrent Energy Holdings, LLC, Torrent Energy Holdings II, LLC and the other parties named therein (incorporated by reference to Exhibit 2.1 to the Registrant’s Form 8-K (File No. 001-38183) filed with the Commission on August 16, 2017.
2.22.2††
Asset Purchase Agreement dated as of May 30, 2017, by and among ESCO Leasing, LLC, Ranger Energy Services, LLC and Tim Hall (incorporated by reference to Exhibit 2.2 to the Registrant’s Form S-1 (File No. 333-218139) filed with the Commission on August 1, 2017).
2.32.3††
Amended and Restated Asset Purchase Agreement dated as of July 31, 2017, by and among ESCO Leasing, LLC, Ranger Energy Services, LLC and Tim Hall (incorporated by reference to Exhibit 2.3 to the Registrant’s Form S-1 (File No. 333-218139) filed with the Commission on August 1, 2017).
3.1 
Amended and Restated Certificate of Incorporation of Ranger Energy Services, Inc. (incorporated by reference to Exhibit 3.1 to the Registrant’s Form 8‑K (File No. 001‑38183) filed with the Commission on August 22, 2017)
3.2 
Amended and Restated Bylaws of Ranger Energy Services, Inc. (incorporated by reference to Exhibit 3.2 to the Registrant’s Form 8‑K (File No. 001‑38183) filed with the Commission on August 22, 2017)
4.1 
Registration Rights Agreement (incorporated by reference to Exhibit 4.1 to the Registrant’s Form 8‑K (File No. 001‑38183) filed with the Commission on August 22, 2017)
4.2 
Stockholders’ Agreement (incorporated by reference to Exhibit 4.2 to the Registrant’s Form 8‑K (File No. 001‑38183) filed with the Commission on August 22, 2017)
*31.110.1
Form of 2019 Performance Stock Unit Award Incentive Agreement
31.1* 
Certification of Chief Executive Officer Pursuant to Rule 13a‑14(a)/15d‑14(a) of the Securities Exchange Act of 1934
*31.231.2* 
Certification of Chief Financial Officer Pursuant to Rule 13a‑14(a)/15d‑14(a) of the Securities Exchange Act of 1934
32.1***32.1 
Certifications of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.2002
32.2***32.2 
Certifications of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.2002
*101.CAL101.CAL* XBRL Calculation Linkbase Document
*101.DEF101.DEF* XBRL Definition Linkbase Document
*101.INS101.INS* XBRL Instance Document
*101.LAB101.LAB* XBRL Labels Linkbase Document
*101.PRE101.PRE* XBRL Presentation Linkbase Document
*101.SCH101.SCH* XBRL Schema Document
   
* Filed as an exhibit to this Quarterly Report on Form 10-Q
** Furnished as an exhibit to this Quarterly Report on Form 10-Q
† Schedules and similar attachments have been omitted pursuant to Item 601(b)(2) of Regulation S-K. The registrant will furnish a supplemental copy of any omitted schedule or similar attachment to the SEC upon request.

SIGNATURES
Pursuant to the requirements the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Ranger Energy Services, Inc.  
   
   
/s/ Darron M. AndersonNovember 7, 2018
Darron M. AndersonDate
President, Chief Executive Officer and Director
(Principal Executive Officer)
/s/ J. Brandon Blossman November 7, 2018July 26, 2019
J. Brandon Blossman Date
Chief Financial Officer  
(Principal Financial Officer)
/s/ Mario H. HernandezJuly 26, 2019
Mario H. HernandezDate
Chief Accounting Officer and
(Principal Accounting Officer)  


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