Company Quick10K Filing
Ranger Energy Services
Price6.49 EPS1
Shares9 P/E9
MCap61 P/FCF2
Net Debt46 EBIT13
TEV107 TEV/EBIT8
TTM 2019-09-30, in MM, except price, ratios
10-Q 2020-06-30 Filed 2020-07-28
10-Q 2020-03-31 Filed 2020-05-01
10-K 2019-12-31 Filed 2020-02-28
10-Q 2019-09-30 Filed 2019-10-25
10-Q 2019-06-30 Filed 2019-07-26
10-Q 2019-03-31 Filed 2019-05-01
10-K 2018-12-31 Filed 2019-03-06
10-Q 2018-09-30 Filed 2018-11-07
10-Q 2018-06-30 Filed 2018-08-08
10-Q 2018-03-31 Filed 2018-05-10
10-K 2017-12-31 Filed 2018-03-13
10-Q 2017-09-30 Filed 2017-11-09
10-Q 2017-06-30 Filed 2017-09-01
8-K 2020-07-23 Earnings, Exhibits
8-K 2020-05-08
8-K 2020-03-31
8-K 2020-03-26
8-K 2020-02-27
8-K 2019-10-24
8-K 2019-07-25
8-K 2019-06-27
8-K 2019-05-15
8-K 2019-04-30
8-K 2018-12-31
8-K 2018-12-04
8-K 2018-11-06
8-K 2018-08-07
8-K 2018-07-30
8-K 2018-06-22
8-K 2018-06-15
8-K 2018-06-04
8-K 2018-05-08
8-K 2018-03-06
8-K 2018-01-05

RNGR 10Q Quarterly Report

Part I - Financial Information
Item 1. Financial Statements
Note 1 - Organization and Business Operations
Note 2 - Summary of Significant Accounting Policies
Note 3 - Revenue From Contracts with Customers
Note 4 - Acquisitions
Note 5 - Assets Held for Sale
Note 6 - Property, Plant and Equipment, Net
Note 7 - Goodwill and Intangible Assets
Note 8 - Accrued Expenses
Note 9 - Capital Leases
Note 10 - Debt
Note 11 - Risk Concentrations
Note 12 - Equity Based Compensation and Profit Interest Awards
Note 13 - Income Taxes
Note 14 - Non-Controlling Interests
Note 15 - Earnings (Loss) per Share
Note 16 - Commitment and Contingencies
Note 17 - Segment Reporting
Note 18 - Subsequent Events
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations
Item 3. Quantitative and Qualitative Disclosure About Market Risks
Item 4. Controls and Procedures
Part II Other Information
Item 1. Legal Proceedings
Item 1A. Risk Factors.
Item 6. Exhibits
EX-31.1 exhibit311_3q2018.htm
EX-31.2 exhibit312_3q2018.htm
EX-32.1 exhibit321_3q2018.htm
EX-32.2 exhibit322_3q2018.htm

Ranger Energy Services Earnings 2018-09-30

Balance SheetIncome StatementCash Flow
3252601951306502017201820192020
Assets, Equity
9070503010-102017201820192020
Rev, G Profit, Net Income
754923-3-29-552017201820192020
Ops, Inv, Fin

10-Q 1 rngr10q-q3fy2018.htm 10-Q Document
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10‑Q
(Mark One)
☒ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2018
or
☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Commission file number 001-38183
RANGER ENERGY SERVICES, INC.
(Exact name of registrant as specified in its charter)
Delaware
81‑5449572
(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)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐
Indicate by check mark whether the registrant has submitted 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, the registrant had 8,929,430 shares of Class A Common Stock and 6,866,154 shares of Class B Common Stock outstanding.



RANGER ENERGY SERVICES, INC.
TABLE OF CONTENTS




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
Assets
 
 
 
 
Current assets
 
 
 
 
Cash and cash equivalents
 
$
2.0

 
$
5.3

Accounts receivable, net
 
49.7

 
32.1

Unbilled revenues
 
4.2

 
6.0

Prepaid expenses and other current assets
 
7.1

 
5.7

Assets held for sale
 
0.6

 
0.6

Total current assets
 
63.6

 
49.7

Property, plant and equipment, net
 
230.7

 
189.2

Goodwill
 

 
9.0

Intangible assets, net
 
10.2

 
10.8

Other assets
 
0.5

 
1.0

Total assets
 
$
305.0

 
$
259.7

Liabilities and Stockholders' Equity
 
 
 
 
Current liabilities
 
 
 
 
Accounts payable
 
$
30.2

 
$
32.0

Accrued expenses
 
27.1

 
11.6

Capital lease obligations, current portion
 
3.9

 
8.0

Long-term debt, current portion
 
11.3

 
1.3

Other current liabilities
 
3.0

 

Total current liabilities
 
75.5

 
52.9

Capital lease obligations
 
6.5

 
1.5

Long-term debt
 
32.8

 
5.8

Other long-term liabilities
 
0.5

 
3.8

Total liabilities
 
115.3

 
64.0

Commitments and contingencies (Note 16)
 

 

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

Accumulated deficit
 
(11.0
)
 
(6.6
)
Additional paid-in capital
 
111.2

 
110.1

Total stockholders' equity
 
100.4

 
103.7

Non-controlling interest
 
89.3

 
92.0

Total stockholders' equity
 
189.7

 
195.7

Total liabilities and stockholders' equity
 
$
305.0

 
$
259.7

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

3


RANGER ENERGY SERVICES, INC.
UNAUDITED INTERIM CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(in millions, except share and per share amounts)
 
 
Three Months Ended
September 30,
 
Nine Months Ended
September 30,
 
 
2018
 
2017
 
2018
 
2017
Revenues
 
 
 
 
 
 
 
 
Well Services
 
$
78.1

 
$
39.0

 
$
206.9

 
$
97.9

Processing Solutions
 
4.0

 
2.1

 
10.9

 
5.9

Total revenues
 
82.1

 
41.1

 
217.8

 
103.8

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

Total cost of services
 
63.6

 
33.9

 
172.8

 
83.3

General and administrative
 
6.6

 
7.9

 
20.8

 
24.0

Depreciation and amortization
 
7.5

 
4.1

 
20.6

 
11.7

Impairment of goodwill
 

 

 
9.0

 

Total operating expenses
 
77.7

 
45.9

 
223.2

 
119.0

Operating income (loss)
 
4.4

 
(4.8
)
 
(5.4
)
 
(15.2
)
Other expenses
 
 
 
 
 
 
 
 
Interest expense, net
 
(0.9
)
 
(4.3
)
 
(1.8
)
 
(5.9
)
Total other expenses
 
(0.9
)
 
(4.3
)
 
(1.8
)
 
(5.9
)
Income (loss) before income tax expense
 
3.5

 
(9.1
)
 
(7.2
)
 
(21.1
)
Tax expense (benefit)
 
(0.5
)
 
0.4

 
0.3

 
0.4

Net income (loss)
 
4.0

 
(9.5
)
 
(7.5
)
 
(21.5
)
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
)
Net income (loss) attributable to Ranger Energy Services, Inc.
 
$
2.1

 
$
(3.5
)
 
$
(4.3
)
 
$
(3.5
)
Earnings (loss) per common share
 
 
 
 
 
 
 
 
Basic
 
$
0.24

 
$
(0.42
)
 
$
(0.48
)
 
$
(0.42
)
Diluted
 
$
0.23

 
$
(0.42
)
 
$
(0.48
)
 
$
(0.42
)
Weighted average common shares outstanding
 
 
 
 
 
 
 
 
Basic
 
8,910,260

 
8,413,178

 
8,897,319

 
8,413,178

Diluted
 
9,156,872

 
8,413,178

 
8,897,319

 
8,413,178

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

4


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

5


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 Services and 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 Holdings, Ranger Energy Holdings II, LLC, a Delaware limited liability company (“Ranger Holdings II”), Torrent Holdings and Torrent Energy Holdings II, LLC, a Delaware limited liability company (“Torrent Holdings II”) and, together 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 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, 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.


6


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.
Business
The Company is one of the largest providers of high‑spec well service rigs and complimentary services in the United States, with a focus on technically demanding unconventional horizontal well completion and production operations. The Company’s 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. The Company also provides rental equipment, including well control packages, hydraulic catwalks and other equipment that are often deployed with its 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, 2017 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 (“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, 2017 and 2016, included in the Annual Report filed on Form 10-K for the year ended December 31, 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 prior to the Offering on August 16, 2017, represent the combined consolidated financial statements of the Predecessor. Financial statements for periods subsequent to the Offering reflect the consolidated financial statements of the Company.
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 nine months ended September 30, 2018 except as discussed in Note 3 — Revenue from Contracts with Customers.
Use of Estimates
The preparation of financial statements in conformity with 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

7



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, and (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
In February 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2016‑2, 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, a sale will only be recognized if the criteria in the new revenue recognition standard are met. ASU 2016‑2 is effective for fiscal years beginning after December 15, 2018, including interim periods within that reporting period, using a modified retrospective approach. The Company will apply the new lease standard as of January 1, 2019 and recognize a cumulative-effect adjustment to retained earnings. We have identified all leases that will have an impact 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 losses 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 step of the goodwill impairment test, thus effectively calculating impairment loss based on the difference between the carrying value and estimated fair value of the reporting units. 
With the exception of the updated standards above, there have been no new accounting pronouncements not yet effective that have significance, or potential significance, to the Company's condensed consolidated financial statements.


8



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.

9



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.


10



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 6 — Property, Plant and Equipment, Net
Property, plant and equipment include the following (in millions):
 
 
Estimated
Useful Life
(years)
 
September 30, 2018
 
December 31, 2017
Machinery and equipment
 
5 - 30
 
$
3.7

 
$
3.7

Vehicles
 
3 - 5
 
9.8

 
2.6

Mechanical refrigeration units
 
30
 
19.0

 
17.1

Natural Gas Liquid ("NGL") storage tanks
 
15
 
4.6

 
4.3

Workover rigs and complimentary equipment
 
5 - 20
 
220.1

 
174.9

Other property, plant and equipment
 
3 - 30
 
17.6

 
12.0

Property, plant and equipment
 
 
 
274.8

 
214.6

Less: accumulated depreciation
 
 
 
(44.1
)
 
(25.4
)
Property, plant and equipment, net
 
 
 
$
230.7

 
$
189.2

Depreciation expense was $20.0 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 million for the three months ended September 30, 2018 and 2017, respectively.
Note 7 — Goodwill and Intangible Assets
Goodwill was $9.0 million as of 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 of a sustained decrease in stock price of the Company. As a result, the Company performed a quantitative impairment test which yielded an impairment charge and recorded an impairment of goodwill of $9.0 million. As of September 30, 2018 there is no goodwill on the Company's consolidated balance sheet.
During the nine months ended September 30, 2018, the Company had nonrecurring fair value measurements related to the impairment of goodwill. The fair values were determined through the use of a blended market and income approach, which represent Level 3 measurements within the fair value hierarchy.
Definite lived intangible assets are comprised of the following (in millions):
 
 
Estimated
Useful Life
(years)
 
September 30, 2018
 
December 31, 2017
Tradenames
 
3
 
$
0.1

 
$
0.1

Customer relationships
 
10-18
 
11.4

 
11.4

Less: accumulated amortization
 
 
 
(1.3
)
 
(0.7
)
Intangible assets, net
 
 
 
$
10.2

 
$
10.8


11



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 million and $0.2 million for the three months ended September 30, 2018 and 2017, 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.
Note 8 — Accrued Expenses
Accrued expenses include the following (in millions):
 
 
September 30, 2018
 
December 31, 2017
Accrued payables
 
$
11.9

 
$
4.8

Accrued payroll
 
10.3

 
2.9

Accrued taxes
 
3.5

 
1.4

Accrued insurance
 
1.4

 
2.5

Accrued expenses
 
$
27.1

 
$
11.6

Note 9 — Capital Leases
The Company leases certain assets under capital leases which expire at various dates through 2021. The assets and liabilities under capital 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 capital leases was $2.5 million and $1.2 million for the nine months ended September 30, 2018 and 2017, respectively. Amortization expense of assets under capital leases was $1.4 million and $0.4 million for the three months ended September 30, 2018 and 2017, respectively.
Aggregate future minimum lease payments under capital leases are as follows (in millions):
As of September 30,
 
Total
2018
 
$
1.1

2019
 
4.3

2020
 
3.9

2021
 
1.4

Thereafter
 
0.4

Total future minimum lease payments
 
11.1

Less: amount representing interest
 
(0.7
)
Present value of future minimum lease payments
 
10.4

Less: current portion of capital lease obligations
 
(3.9
)
Total capital lease obligations, less current portion
 
$
6.5


12



Note 10 — Debt
The aggregate carrying amounts, net of issuance costs, of the Company'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

In connection with the Offering and the ESCO Acquisition 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.
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'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'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's average excess availability under the Credit Facility. The applicable margin for LIBOR loans is 1.50% and the applicable margin for Base Rate loans are 0.50% as of September 30, 2018. 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.
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.

13



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 September 30, 2018, the Company has borrowed $18.5 million under the Credit Facility. The Company has a borrowing capacity of approximately $40.2 million under the Credit Facility, with approximately $21.7 million available as of September 30, 2018. The Company was in compliance with the Credit Facility covenants as of September 30, 2018.
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 September 30, 2018 approximated $0.6 million.
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, which was used by the Company to acquire certain capital equipment. Subsequent financings could be made, as agreed by the Company and Lender. Amounts outstanding under the Financing Agreement are payable ratably over 48 months through the maturity of July 2022. 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"), which was 2.2% as of September 30, 2018. The Financing Agreement requires that the Company maintain leverage ratios of 5.00 to 1.00 as of September 30, 2018, 3.50 to 1.00 as of December 31, 2018 and 2.50 to 1.00 for periods thereafter. The Company was in compliance with the covenants under the Financing Agreement as of September 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

The Company capitalized fees of $0.7 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 September 30, 2018 approximated $0.7 million.
Note 11 — Risk Concentrations
Customer Concentrations 
For the nine months ended September 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 Resources 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, 2017two 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.

14



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 563,002 restricted shares granted under the LTIP.
Time Based Restricted Stock
During the nine months ended September 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, 2018, was $0.9 million. There was approximately $3.3 million of unrecognized compensation expense related to outstanding restricted shares as of September 30, 2018, which is expected to be recognized over a weighted average period of 2.7 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 nine months ended September 30, 2018, the Company granted 39,715 target shares of market based performance restricted stock units at a grant date fair value of $8.59 per share to certain employees. The market based performance restricted stock units cliff vest on December 31, 2020. The performance criteria applicable to such awards is relative total shareholder return, which measures the Company's total shareholder return as compared to the total shareholder return of the peer group identified by the board of directors. As of September 30, 2018, 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 2.3 years.
During the nine months ended September 30, 2018, 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 applicable to such awards is absolute total shareholder return, which measures the Company's total shareholder return as compared to the value of the Company's Class A Common Stock at the time of the Offering of $14.50. As of September 30, 2018, there was $0.1 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 2.3 years.
During the nine months ended September 30, 2018 and 2017, 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. The total unrecognized compensation cost related to unvested awards at September 30, 2018 is $0.4 million and is expected to be recognized over the next 1.8 years.

15



Note 13 — 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 nine months ended September 30, 2018 and 2017 was 3.6% and 0.0%, 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.
Note 14 — Non-Controlling Interests
The Company has ownership interests in Ranger LLC, which is consolidated within the Company’s financial statements but is not wholly owned by the Company. During the nine months ended September 30, 2018, 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 accounted for as equity transactions.
Note 15 — 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 the three and nine months ended September 30, 2018 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, 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.

16



Note 16 — Commitment 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 Company terminated the employment of one of its officers. As a result, the former officer became entitled 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 Company has $0.5 million of severance liability recorded in the accompanying condensed consolidated financial statements within accrued expenses.
Note 17 — Segment Reporting
The Company’s operations are all located in the United States and organized into two reportable segments: Well Services and Processing Solutions. The Company’s reportable segments comprise the structure used by its Chief Operating Decision Maker (“CODM”) to make key operating decisions and assess performance during the years presented in the accompanying condensed consolidated financial statements. The Company’s CODM evaluates the segments’ operating performance based on multiple measures including Adjusted Earnings before Interest, Tax, Depreciation and Amortization (“Adjusted EBITDA”), rig hours and rig utilization. The following is a description of the segments:
Well Services.  The Company’s well service rigs facilitate operations throughout the lifecycle of a well, including (i) well completion support; (ii) 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 service rigs are designed to support growing U.S. horizontal well demands. In addition to its core well service rig operations, the Company offers a suite of complementary services, including wireline, snubbing, fluid management and well service-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 either 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.

17



Segment information as of September 30, 2018 and December 31, 2017 and for the three and nine months ended September 30, 2018 and 2017 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 September 30, 2017
Revenues
 
$

 
$
39.0

 
$
2.1

 
$
41.1

Cost of services
 
$

 
$
33.1

 
$
0.8

 
$
33.9

Depreciation and amortization
 
$

 
$
3.8

 
$
0.3

 
$
4.1

Operating income (loss)
 
$

 
$
(5.2
)
 
$
0.4

 
$
(4.8
)
Interest expense, net
 
$

 
$
(4.3
)
 
$

 
$
(4.3
)
Net income (loss)
 
$

 
$
(9.9
)
 
$
0.4

 
$
(9.5
)
Capital expenditures
 
$

 
$
8.2

 
$
1.1

 
$
9.3

 
 
Nine Months Ended September 30, 2017
Revenues
 
$

 
$
97.9

 
$
5.9

 
$
103.8

Cost of services
 
$

 
$
81.1

 
$
2.2

 
$
83.3

Depreciation and amortization
 
$

 
$
10.9

 
$
0.8

 
$
11.7

Operating income (loss)
 
$

 
$
(16.0
)
 
$
0.8

 
$
(15.2
)
Interest expense, net
 
$

 
$
(5.8
)
 
$
(0.1
)
 
$
(5.9
)
Net income (loss)
 
$

 
$
(22.3
)
 
$
0.8

 
$
(21.5
)
Capital expenditures
 
$

 
$
15.2

 
$
1.2

 
$
16.4

 
 
As of December 31, 2017
Property, plant and equipment, net
 
$
6.4

 
$
157.4

 
$
25.4

 
$
189.2

Total assets
 
$
6.4

 
$
225.1

 
$
28.2

 
$
259.7


18



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. We assume no obligation to update any of these forward‑looking statements.
Overview
We are one of the largest providers of high‑spec well service rigs and complimentary services in the United States, with a focus on technically demanding unconventional horizontal well completion and production operations. We believe that our fleet of 136 well service rigs are 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 E&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 have 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 SCOOP and STACK 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.

19



We conduct our operations through two segments: Well Services and Processing Solutions. Our Well 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 Processing Solutions segment engages in the rental, installation, commissioning, start‑up, operation and maintenance of mechanical refrigeration units (“MRUs”), NGL stabilizer units, NGL storage units and related equipment. We operate 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 SCOOP and STACK plays. For additional information about our assets and operations, please see Note 17 — Segment Reporting, to the unaudited interim condensed consolidated financial statements.
Initial Public Offering
On August 16, 2017, we completed the Offering 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. 
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. Please see Note 3 — Revenue from Contracts with Customers to the unaudited interim condensed consolidated financial statements.
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 management uses a variety of metrics to analyze our operating results and profitability. These metrics include, among others, the following:
Revenues;
Operating Income (Loss); and
Adjusted EBITDA.
In addition, within our Well Services segment, our management intends to use additional metrics to analyze our activity levels and profitability. These metrics include, among others, the following:
Rig Hours; and

20



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), depreciation and amortization, equity‑based compensation, 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. 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 Services 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 Services 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 service rigs in our fleet during such period, as aggregated on a monthly basis utilizing a mid-month convention whereby a well service rig added to our fleet during a month, meaning that we have taken delivery of such well service 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 service 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 are (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 service 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 nine months ended September 30, 2018 and 2017, our rig utilization as measured by average monthly hours per rig was approximately 183 hours and 196 hours, respectively. Actual aggregate operating well service rig hours increased from approximately 137,500 in the nine months ended September 30, 2017, to approximately 224,600 in the nine months ended September 30, 2018. The increase in rig hours resulted from 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 $505 and $448, respectively.
For the three months ended September 30, 2018 and 2017, our rig utilization as measured by average monthly hours per rig was approximately 178 hours and 199 hours, respectively. Actual aggregate operating well service rig hours increased from approximately 59,300 in the three months ended September 30, 2017 to approximately 74,200 in the three months ended September 30, 2018.  The increase in rig hours resulted from 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

21



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 $519 and $443, 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 Reorganization 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" and, together, the "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'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.

22



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. 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.
Results of Operations
Three Months Ended September 30, 2018 compared to Three Months Ended September 30, 2017
The following table presents our Predecessor’s selected operating data for the three months ended September 30, 2018 as compared to the three months ended September 30, 2017.
 
 
September 30,
 
Change
 
 
2018
 
2017
 
$
 
%
Revenues
 
 
 
 
 
 
 
 
Well Services
 
$
78.1

 
$
39.0

 
$
39.1

 
100
 %
Processing Solutions
 
4.0

 
2.1

 
1.9

 
90
 %
Total revenues
 
82.1

 
41.1

 
41.0

 
100
 %
Operating expenses
 
 
 
 
 
 
 


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


Well Services
 
61.8

 
33.1

 
28.7

 
87
 %
Processing Solutions
 
1.8

 
0.8

 
1.0

 
125
 %
Total cost of services
 
63.6

 
33.9

 
29.7

 
88
 %
General and administrative
 
6.6

 
7.9

 
(1.3
)
 
(16
)%
Depreciation and amortization
 
7.5

 
4.1

 
3.4

 
83
 %
Impairment of goodwill
 

 

 

 

Total operating expenses
 
77.7

 
45.9

 
31.8

 
69
 %
Operating income (loss)
 
4.4

 
(4.8
)
 
9.2

 
192
 %
Other expenses
 
 
 
 
 
 
 


Interest expense, net
 
(0.9
)
 
(4.3
)
 
(3.4
)
 
(79
)%
Total other expenses
 
(0.9
)
 
(4.3
)
 
(3.4
)
 
(79
)%
Income (loss) before income tax expense
 
3.5

 
(9.1
)
 
12.6

 
138
 %
Tax expense (benefit)
 
(0.5
)
 
0.4

 
(0.9
)
 
(225
)%
Net income (loss)
 
$
4.0

 
$
(9.5
)
 
$
13.5

 
142
 %
Revenues. Revenues for the three months ended September 30, 2018 increased $41.0 million, or 100%, to $82.1 million from $41.1 million for the three months ended September 30, 2017. The increase in revenues by segment was as follows:
Well Services. Well Services revenues for the three months ended September 30, 2018 increased $39.1 million, or 100%, to $78.1 million from $39.0 million for the three months ended September 30, 2017. The increase was due to an increased number of rigs, to an average of 139 from an average of 99 rigs, providing workover rig services, which is primarily related to the ESCO Acquisition and accounted for $9.2 million, or 24% of the segment increase. The increase in workover rig services included a 25% increase in total rig hours to 74,200 from 59,300 for the three months ended September 30, 2018 compared to the three months ended September 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.
Processing Solutions. Processing Solutions revenues for the three months ended September 30, 2018 increased $1.9 million, or 90%, to $4.0 million from $2.1 million for the three months ended September 30, 2017. The increase was primarily attributable to the additional MRUs and tanks we have rented to customers as well as additional mobilization revenue due to equipment going to customers.
Cost of services (excluding depreciation and amortization shown separately). Cost of services for the three months ended September 30, 2018 increased $29.7 million, or 88%, to $63.6 million from $33.9 million for the three months ended September 30, 2017. As a percentage of revenue, cost of services was 77% and 82% for the three months ended September 30, 2018 and 2017, respectively. The increase in cost of services by segment was as follows:

23



Well Services. Well Services cost of services for the three months ended September 30, 2018 increased $28.7 million, or 87% to $61.8 million from $33.1 million for the three 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 three months ended September 30, 2018 increased $1.0 million, or 125%, to $1.8 million from $0.8 million for the three months ended September 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.

24



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.

25



General & Administrative. General and administrative expenses for the nine months ended September 30, 2018 decreased $3.2 million, or 13%, to $20.8 million from $24.0 million for the nine 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 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. The decrease was primarily attributable to a decrease in expenses due to the expenses for 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.
Depreciation and Amortization. Depreciation and amortization for the nine months ended September 30, 2018 increased $8.9 million, or 76%, to $20.6 million from $11.7 million for the nine 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 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 primarily attributable to fixed assets that were put in place during 2017 and the nine months 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.
Impairment of goodwill.  Impairment of goodwill for the nine months ended September 30, 2018 was $9.0 million compared to no impairment for the nine months ended September 30, 2017. During the nine months ended September 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 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. Therefore we recorded an impairment charge based on the excess of our carrying amount over the fair value. Please see Note 7 — Goodwill and Intangible Assets to the unaudited interim condensed consolidated financial statements for further details.
Interest Expense, net. Interest expense, net for the nine months ended September 30, 2018 decreased $4.1 million, or 69%, to $1.8 million from $5.9 million for the nine months ended September 30, 2017. The decrease to interest expense, net was attributable to the repayment of the Bridge Loan 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 during the nine months ended September 30, 2018 compared to the nine months ended September 30, 2017.
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.

26



Three Months Ended September 30, 2018 compared to Three Months Ended September 30, 2017
 
 
Three Months Ended September 30, 2018
 
 
 
 
Well
 
Processing
 
 
 
 
Other
 
Services
 
Solutions
 
Total
 
 
(in millions)
Net income (loss)
 
$
(8.2
)
 
$
11.0

 
$
1.2

 
$
4.0

Interest expense, net
 
0.9

 

 

 
0.9

Tax expense
 
0.4

 
(0.9