Company Quick10K Filing
Ranger Energy Services
Closing Price ($) Shares Out (MM) Market Cap ($MM)
$0.00 9 $67
10-Q 2019-10-25 Quarter: 2019-09-30
10-Q 2019-07-26 Quarter: 2019-06-30
10-Q 2019-05-01 Quarter: 2019-03-31
10-K 2019-03-06 Annual: 2018-12-31
10-Q 2018-11-07 Quarter: 2018-09-30
10-Q 2018-08-08 Quarter: 2018-06-30
10-Q 2018-05-10 Quarter: 2018-03-31
10-K 2018-03-13 Annual: 2017-12-31
10-Q 2017-11-09 Quarter: 2017-09-30
10-Q 2017-09-01 Quarter: 2017-06-30
8-K 2019-10-24 Earnings, Exhibits
8-K 2019-07-25 Earnings, Exhibits
8-K 2019-06-27 Other Events, Exhibits
8-K 2019-05-15 Shareholder Vote
8-K 2019-04-30 Earnings, Exhibits
8-K 2018-12-31 Earnings, Exhibits
8-K 2018-12-04 Officers
8-K 2018-11-06 Earnings, Exhibits
8-K 2018-08-07 Earnings, Exhibits
8-K 2018-07-30 Officers, Other Events, Exhibits
8-K 2018-06-22 Enter Agreement, Off-BS Arrangement, Exhibits
8-K 2018-06-15 Shareholder Vote
8-K 2018-06-04 Officers, Regulation FD, Exhibits
8-K 2018-05-08 Earnings, Exhibits
8-K 2018-03-06 Earnings, Exhibits
8-K 2018-01-05 Officers, Exhibits
RNGR 2019-09-30
Part I - Financial Information
Item 1. Financial Statements
Note 1 - Organization and Business Operations
Note 2 - Summary of Significant Accounting Policies
Note 3 - Acquisitions
Note 4 - Property and Equipment, Net
Note 5 - Goodwill and Intangible Assets
Note 6 - Accrued Expenses
Note 7 - Leases
Note 8 - Debt
Note 9-Equity
Note 10 - Risk Concentrations
Note 11 - Income Taxes
Note 12 - Earnings (Loss) per Share
Note 13 - Commitments and Contingencies
Note 14 - Segment Reporting
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations
Item 3. Quantitative and Qualitative Disclosures About Market Risks
Item 4. Controls and Procedures
Part II Other Information
Item 1. Legal Proceedings
Item 1A. Risk Factors
Item 2. Unregistered Sales of Securities and Use of Proceeds
Item 6. Exhibits
EX-31.1 a3q19-exhibit311_dma.htm
EX-31.2 a3q19-exhibit312_jbb.htm
EX-32.1 a3q19-exhibit321_dma.htm
EX-32.2 a3q19-exhibit322_jbb.htm

Ranger Energy Services Earnings 2019-09-30

RNGR 10Q Quarterly Report

Balance SheetIncome StatementCash Flow

Comparables ($MM TTM)
Ticker M Cap Assets Liab Rev G Profit Net Inc EBITDA EV G Margin EV/EBITDA ROA
CELP 132 170 116 375 50 15 21 210 13% 10.0 9%
RNGR 67 318 116 340 0 11 51 130 0% 2.6 3%
NES 63 285 68 187 0 -27 9 93 0% 10.3 -10%
QES 54 322 137 578 0 -24 29 73 0% 2.5 -7%
BAS 51 702 533 864 200 -129 44 314 23% 7.2 -18%
KEG 41 404 474 97 -89 10 255 20% 25.2 -22%
RCON 26 122 35 -23 0 48 49 -20 -2% -0.4 40%
ENSV 23 49 43 50 11 -2 7 25 22% 3.3 -4%
NOA
NEX

10-Q 1 rngr3q19form10-q.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, 2019
or
☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Commission file number 001-38183
ranger_logoa17.jpg
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)
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
 
Trading Symbol(s)
 
Name of each exchange on which registered
Class A Common Stock, $0.01 par value
 
RNGR
 
New York Stock Exchange

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T 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 October 23, 2019, the registrant had 8,775,220 shares of Class A Common Stock and 6,866,154 shares of Class B Common Stock outstanding.
 
 
 
 
 



RANGER ENERGY SERVICES, INC.
TABLE OF CONTENTS
 
 
Page
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 



PART I – FINANCIAL INFORMATION
ITEM 1. Financial Statements
RANGER ENERGY SERVICES, INC.
UNAUDITED INTERIM CONDENSED CONSOLIDATED BALANCE SHEETS
(in millions, except share amounts)
 
 
September 30, 2019
 
December 31, 2018
Assets
 
 
 
 
Cash and cash equivalents
 
$
8.0

 
$
2.6

Accounts receivable, net
 
48.9

 
45.4

Contract assets
 
4.2

 
3.1

Inventory
 
2.5

 
4.9

Prepaid expenses
 
4.9

 
5.1

Total current assets
 
68.5

 
61.1

 
 
 
 
 
Property and equipment, net
 
222.8

 
229.8

Intangible assets, net
 
9.5

 
10.0

Operating lease right-of-use assets
 
6.9

 

Other assets
 
0.7

 
1.6

Total assets
 
$
308.4

 
$
302.5

 
 
 
 
 
Liabilities and Stockholders' Equity
 
 
 
 
Accounts payable
 
$
9.5

 
$
17.2

Accrued expenses
 
25.8

 
18.5

Finance lease obligations, current portion
 
5.1

 
4.4

Long-term debt, current portion
 
15.8

 
15.8

Other current liabilities
 
2.7

 
3.0

Total current liabilities
 
58.9

 
58.9

 
 
 
 
 
Operating lease right-of-use obligations
 
4.8

 

Finance lease obligations
 
4.5

 
6.6

Long-term debt, net
 
37.0

 
44.7

Other long-term liabilities
 
0.7

 
0.3

Total liabilities
 
$
105.9

 
$
110.5

 
 
 
 
 
Commitments and contingencies (Note 13)
 

 

 
 
 
 
 
Stockholders' equity
 
 
 
 
Preferred stock, $0.01 per share; 50,000,000 shares authorized; no shares issued or outstanding as of September 30, 2019 and December 31, 2018
 

 

Class A Common Stock, $0.01 par value, 100,000,000 shares authorized; 8,781,528 shares outstanding and 8,829,002 shares issued as of September 30, 2019; and 8,448,527 shares issued and outstanding as of December 31, 2018
 
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, 2019 and December 31, 2018
 
0.1

 
0.1

Less: Class A Common Stock held in treasury, at cost (47,474 shares)
 
(0.3
)
 

Accumulated deficit
 
(7.4
)
 
(9.9
)
Additional paid-in capital
 
121.5

 
111.6

Total stockholders' equity
 
114.0

 
101.9

Non-controlling interest
 
88.5

 
90.1

Total stockholders' equity
 
202.5

 
192.0

Total liabilities and stockholders' equity
 
$
308.4

 
$
302.5

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
 
Nine Months Ended
 
 
September 30,
 
September 30,
 
 
2019
 
2018
 
2019
 
2018
Revenues
 
 
 
 
 
 
 
 
High specification rigs
 
$
32.5

 
38.7

 
$
97.3

 
$
114.6

Completion and other services
 
45.3

 
39.4

 
143.2

 
92.3

Processing solutions
 
6.3

 
4.0

 
16.2

 
10.9

Total revenues
 
84.1

 
82.1

 
256.7

 
217.8

 
 
 
 
 
 
 
 
 
Operating expenses
 
 
 
 
 
 
 
 
Cost of services (exclusive of depreciation and amortization):
 
 
 
 
 
 
 
 
High specification rigs
 
29.3

 
33.2

 
85.4

 
98.3

Completion and other services
 
34.6

 
28.0

 
107.5

 
68.2

Processing solutions
 
2.8

 
1.8

 
6.9

 
5.1

Total cost of services
 
66.7

 
63.0

 
199.8

 
171.6

General and administrative
 
6.7

 
7.2

 
20.2

 
22.0

Depreciation and amortization
 
9.1

 
7.5

 
25.9

 
20.6

Impairment of goodwill
 

 

 

 
9.0

Total operating expenses
 
82.5

 
77.7

 
245.9

 
223.2

 
 
 
 
 
 
 
 
 
Operating income (loss)
 
1.6

 
4.4

 
10.8

 
(5.4
)
 
 
 
 
 
 
 
 
 
Other expenses
 
 
 
 
 
 
 
 
Interest expense, net
 
1.4

 
0.9

 
4.6

 
1.8

Total other expenses
 
1.4

 
0.9

 
4.6

 
1.8

 
 
 
 
 
 
 
 
 
Income (loss) before income tax expense
 
0.2

 
3.5

 
6.2

 
(7.2
)
Tax expense (benefit)
 
1.1

 
(0.5
)
 
1.7

 
0.3

Net income (loss)
 
(0.9
)
 
4.0

 
4.5

 
(7.5
)
Less: Net income (loss) attributable to non-controlling interests
 
(0.4
)
 
1.9

 
2.0

 
(3.2
)
Net income (loss) attributable to Ranger Energy Services, Inc.
 
$
(0.5
)
 
$
2.1

 
$
2.5

 
$
(4.3
)
 
 
 
 
 
 
 
 
 
Earnings (loss) per common share
 
 
 
 
 
 
 
 
Basic
 
$
(0.06
)
 
$
0.25

 
$
0.29

 
$
(0.51
)
Diluted
 
$
(0.06
)
 
$
0.24

 
$
0.26

 
$
(0.51
)
Weighted average common shares outstanding
 
 
 
 
 
 
 
 
Basic
 
8,769,389

 
8,428,271

 
8,591,128

 
8,418,607

Diluted
 
8,769,389

 
8,674,883

 
9,459,786

 
8,418,607

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 STOCKHOLDERS’ EQUITY
(in millions, except share amounts)
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2019
2018
2019
2018
 
2019
2018
2019
2018
 
Quantity
Amount
 
Quantity
Amount
Shares, Class A Common Stock
 
 
 
 
 
 
 
 
 
Balance, beginning of period
8,717,026

8,416,641

$
0.1

$
0.1

 
8,448,527

8,413,178

$
0.1

$
0.1

Issuance of shares under share-based compensation plans
113,159

27,131



 
214,780

31,779



Shares withheld for taxes on equity transactions
(1,183
)
(1,678
)


 
(41,202
)
(2,863
)


Issuance of Class A Common Stock to related party




 
206,897




Balance, end of period
8,829,002

8,442,094

$
0.1

$
0.1

 
8,829,002

8,442,094

$
0.1

$
0.1

 
 
 
 
 
 
 
 
 
 
Shares, Class B Common Stock
 
 
 
 
 
 
 
 
 
Balance, beginning of period
6,866,154

6,866,154

$
0.1

$
0.1

 
6,866,154

6,866,154

$
0.1

$
0.1

Balance, end of period
6,866,154

6,866,154

$
0.1

$
0.1

 
6,866,154

6,866,154

$
0.1

$
0.1

 
 
 
 
 
 
 
 
 
 
Treasury Stock
 
 
 
 
 
 
 
 
 
Balance, beginning of period


$

$

 


$

$

Repurchase of Class A Common Stock
47,474


$
(0.3
)
$

 
47,474


$
(0.3
)
$

Balance, end of period
47,474


$
(0.3
)
$

 
47,474


$
(0.3
)
$

 
 
 
 
 
 
 
 
 
 
Accumulated deficit
 
 
 
 
 
 
 
 
 
Balance, beginning of period
 
 
$
(6.9
)
$
(13.0
)
 
 
 
$
(9.9
)
$
(6.6
)
Net income (loss) attributable to controlling interest
 
 
(0.5
)
2.1

 
 
 
2.5

(4.3
)
Balance, end of period
 
 
$
(7.4
)
$
(10.9
)
 
 
 
$
(7.4
)
$
(10.9
)
 
 
 
 
 
 
 
 
 
 
Additional paid-in capital
 
 
 
 
 
 
 
 
 
Balance, beginning of period
 
 
$
119.9

$
110.5

 
 
 
$
111.6

$
110.1

Equity based compensation amortization
 
 
0.8

0.7

 
 
 
2.2

1.1

Shares withheld for taxes on equity transactions
 
 
0.1


 
 
 
(0.3
)

Issuance of Class A Common Stock to related party
 
 


 
 
 
3.0


Benefit from reversal of valuation allowance
 
 
0.6


 
 
 
1.2


Impact of transactions affecting non-controlling interest
 
 
0.1


 
 
 
3.8


Balance, end of period
 
 
$
121.5

$
111.2

 
 
 
$
121.5

$
111.2

 
 
 
 
 
 
 
 
 
 
Total controlling interest shareholders’ equity
 
 
 
 
 
 
 
 
 
Balance, beginning of period
 
 
$
113.2

$
97.7

 
 
 
$
101.9

$
103.7

Net income (loss) attributable to controlling interest
 
 
(0.5
)
2.1

 
 
 
2.5

(4.3
)
Equity based compensation amortization
 
 
0.8

0.7

 
 
 
2.2

1.1

Shares withheld for taxes on equity transactions
 
 
0.1


 
 
 
(0.3
)

Issuance of Class A Common Stock to related party
 
 


 
 
 
3.0


Benefit from reversal of valuation allowance
 
 
0.6


 
 
 
1.2


Impact of transactions affecting non-controlling interest
 
 
0.1


 
 
 
3.8


Repurchase of Class A Common Stock
 
 
(0.3
)

 
 
 
(0.3
)

Balance, end of period
 
 
$
114.0

$
100.5

 
 
 
$
114.0

$
100.5

 
 
 
 
 
 
 
 
 
 
Non-controlling interest
 
 
 
 
 
 
 
 
 
Balance, beginning of period
 
 
$
88.9

$
87.4

 
 
 
$
90.1

$
92.0

Net income (loss) attributable to non-controlling interest
 
 
(0.4
)
1.9

 
 
 
2.0

(3.2
)
Equity based compensation amortization
 
 
0.1


 
 
 
0.2

0.5

Impact of transactions affecting non-controlling interest
 
 
(0.1
)

 
 
 
(3.8
)

Balance, end of period
 
 
$
88.5

$
89.3

 
 
 
$
88.5

$
89.3

 
 
 
 
 
 
 
 
 
 
Total Equity
 
 
 
 
 
 
 
 
 
Balance, beginning of period
 
 
$
202.1

$
185.1

 
 
 
$
192.0

$
195.7

Total income (loss)
 
 
(0.9
)
4.0

 
 
 
4.5

(7.5
)
Equity based compensation amortization
 
 
0.9

0.7

 
 
 
2.4

1.6

Shares withheld for taxes on equity transactions
 
 
0.1


 
 
 
(0.3
)

Issuance of Class A Common Stock to related party
 
 


 
 
 
3.0


Benefit from reversal of valuation allowance
 
 
0.6


 
 
 
1.2


Repurchase of Class A Common Stock
 
 
(0.3
)

 
 
 
(0.3
)

Balance, end of period
 
 
$
202.5

$
189.8

 
 
 
$
202.5

$
189.8

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

5


RANGER ENERGY SERVICES, INC.
UNAUDITED INTERIM CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(in millions)
 
 
Nine Months Ended
 
 
September 30,
 
 
2019
 
2018
Cash Flows from Operating Activities
 
 
 
 
Net income (loss)
 
$
4.5

 
$
(7.5
)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
 
 
 
 
Depreciation and amortization
 
25.9

 
20.6

Impairment of goodwill
 

 
9.0

Equity based compensation
 
2.4

 
1.6

Other costs, net
 
1.8

 

Changes in operating assets and liabilities, net of effect of acquisitions
 
 
 
 
Accounts receivable
 
(3.5
)
 
(17.7
)
Contract assets
 
(1.1
)
 
1.7

Inventory
 
2.4

 

Prepaid expenses
 
0.2

 
(1.3
)
Other assets
 
0.9

 
0.4

Accounts payable
 
(6.0
)
 
8.4

Accrued expenses
 
8.0

 
10.7

Other long-term liabilities
 
0.8

 
(1.0
)
Net cash provided by operating activities
 
36.3

 
24.9

 
 
 
 
 
Cash Flows from Investing Activities
 
 
 
 
Purchase of property and equipment
 
(19.6
)
 
(56.1
)
Proceeds from disposal of property and equipment
 
0.6

 
4.0

Acquisitions, net of cash received
 

 
(4.0
)
Net cash used in investing activities
 
(19.0
)
 
(56.1
)
 
 
 
 
 
Cash Flows from Financing Activities
 
 
 
 
Borrowings under line of credit facility
 
25.5

 
41.8

Principal payments on line of credit facility
 
(26.0
)
 
(23.4
)
Borrowings on Encina Master Financing Agreement, net of deferred financing costs
 

 
21.3

Principal payments on Encina Master Financing Agreement
 
(7.3
)
 
(1.0
)
Principal payments on ESCO Note Payable
 

 
(1.2
)
Principal payments on financing lease obligations
 
(3.5
)
 
(9.6
)
Repurchase of Class A Common Stock
 
(0.3
)
 

Shares withheld on equity transactions
 
(0.3
)
 

Net cash (used in) provided by financing activities
 
(11.9
)
 
27.9

 
 
 
 
 
Increase (decrease) in Cash and Cash equivalents
 
5.4

 
(3.3
)
Cash and Cash Equivalents, Beginning of Period
 
2.6

 
5.3

Cash and Cash Equivalents, End of Period
 
$
8.0

 
$
2.0

 
 
 
 
 
Supplemental Cash Flows Information
 
 
 
 
Interest paid
 
$
3.5

 
$
1.3

Supplemental Disclosure of Non-cash Investing and Financing Activity
 
 
 
 
Non-cash capital expenditures
 
$
(2.3
)
 
$
5.3

Non-cash additions to fixed assets through financing leases
 
$
(2.0
)
 
$
(10.4
)
Initial non-cash operating lease right-of-use asset additions
 
$
(8.3
)
 
$

Issuance of Class A Common Stock to related party
 
$
3.0

 
$

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

6


RANGER ENERGY SERVICES, INC.
NOTES TO UNAUDITED INTERIM CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Note 1 — Organization and Business Operations
Organization
Ranger Energy Services, Inc. (“Ranger” or the “Company”) was incorporated as a Delaware corporation in February 2017. Ranger is a holding company, the sole material assets of which consist of membership interests in RNGR Energy Services, LLC, a Delaware limited liability company (“Ranger LLC”). Ranger LLC owns all of the outstanding equity interests in Ranger Energy Services, LLC (“Ranger Services”) and Torrent Energy Services, LLC (“Torrent Services”), the subsidiaries through which it operates its assets. 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 with, among others, Ranger LLC, Ranger Energy Holdings LLC, Ranger Energy Holdings II, LLC, Torrent Energy Holdings, LLC and Torrent Energy Holdings II, LLC. In connection with the Master Reorganization Agreement, an aggregate of $3.0 million to 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 Company’s initial public offering (the “Offering”) in, at the Company’s option, cash, shares of Class A Common Stock (with such shares to be valued based on the greater of the price of the Class A Common Stock in the Offering and a 30-day weighted average price) or a combination thereof (included within Other current liabilities on the accompanying consolidated balance sheet as of December 31, 2018). During the nine months ended September 30, 2019, the Company settled the $3.0 million liability. See Note 9 — Equity for further details of the Company’s equity position.
Business
The Company is one of the largest providers of high specification (“high‑spec”) well service rigs and associated services in the United States, with a focus on technically demanding unconventional horizontal well completion and production operations. We believe that our fleet of 139 well service rigs is among the newest and most advanced in the industry and, based on our historical rig utilization and feedback from our customers, we believe that we are an operator of choice for U.S. onshore exploration and production (“E&P”) companies that require completion and production services at increasing lateral lengths. Our high‑spec well service rigs facilitate operations throughout the lifecycle of a well, including (i) completion services, such as milling out composite plugs after the hydraulic fracturing process and the installation of downhole production equipment; (ii) workover, including retrieval and replacement of existing production tubing; (iii) well maintenance, including replacement of downhole artificial lift components; and (iv) decommissioning, such as plugging and abandonment operations. The Company also provides Completion and Other Services, which provides services necessary to bring and maintain a well on production and primarily includes (i) wireline perforating and pumpdown services and (ii) snubbing services often utilized in conjunction with our high-spec rigs to convey equipment in and out of a well during completion and workover activities. The Company provides rental equipment, including well control packages, hydraulic catwalks and other equipment that is often deployed with our well service rigs. 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 and Sooner Trend Anadarko Basin Canadian and Kingfisher counties plays.
Note 2 — Summary of Significant Accounting Policies
Basis of Presentation
The consolidated balance sheet as of December 31, 2018 has been derived from audited financial statements and the unaudited condensed consolidated financial statements have been prepared in accordance with generally accepted accounting principles in the United States (“US GAAP”) for interim financial information and the Securities and Exchange Commission’s (the “SEC”) instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly certain notes and other information have been condensed or omitted. The unaudited condensed consolidated financial statements reflect all normal and recurring adjustments that are, in the opinion of management, necessary for the fair presentation of the results of operations for the interim periods. These interim financial statements, should be read in conjunction with the consolidated financial statements and related notes for the years ended December 31, 2018 and 2017, included in the Annual Report filed on Form 10-K for the years ended December 31, 2018 and 2017 (the “Annual Report”). Interim results for the periods presented may not be indicative of results that will be realized for future periods.

7



The Company has made certain reclassifications to our prior period operating revenue, cost of sales and general and administrative amounts due to the change in reportable segments whereby our High Specification Rig and Completion and Other Services segments were bifurcated from our legacy Well Services segment as a result of our fourth quarter 2018 operating segment changes. None of these reclassifications have an impact on our condensed consolidated operations results, cash flows or financial position.
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 nine months ended September 30, 2019, except as discussed in Note 7 — Leases and below.
Use of Estimates
The preparation of financial statements in conformity with US GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the reporting period. Management uses historical and other pertinent information to determine these estimates. Actual results could differ from such estimates. Areas where critical accounting estimates are made by management include:
Depreciation and amortization of property and equipment and intangible assets;
Impairment of property and equipment, goodwill and intangible assets;
Allowance for doubtful accounts;
Fair value of assets acquired and liabilities assumed in an acquisition; and
Equity‑based compensation.
Emerging Growth Company status
The Company is an “emerging growth company” as defined in the Jumpstart Our Business Startups Act of 2012 (the “JOBS Act”). The Company will remain an emerging growth company until the earlier of (1) the last day of its fiscal year (a) following the fifth anniversary of the completion of the Offering, (b) in which its total annual gross revenue is at least $1.07 billion, or (c) in which the Company is deemed to be a large accelerated filer, which means the market value of the Company’s common stock that is held by non-affiliates exceeds $700.0 million as of the last business day of its most recently completed second fiscal quarter, or (2) the date on which the Company has issued more than $1.0 billion in non-convertible debt securities during the prior three-year period. An emerging growth company may take advantage of specified reduced reporting and other burdens that are otherwise applicable generally to public companies. The Company has irrevocably opted out of the extended transition period and, as a result, the Company will adopt new or revised accounting standards on the relevant dates on which adoption of such standards is required for other public companies.
New Accounting Pronouncements
Recently Adopted Accounting Standards
In February 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2016‑02, Leases, amending the current accounting for leases. Under the new provisions, all lessees will report a Right‑of‑Use (“ROU”) 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.
Effective January 1, 2019, the Company has adopted ASU 2016-02 and elected the following practical expedients and accounting policy elections for recognition, measurement and presentation:
The optional transition method, therefore will not adjust comparative period financial information or make the new required lease disclosures for periods prior to the effective date;
the package of practical expedients to not reassess prior conclusions related to (i) contracts containing leases, (ii) lease classification and (iii) initial direct costs;
to make the accounting policy election for short-term leases, or leases with terms of 12 months or less, therefore the lease payments will be recorded as an expense on a straight line basis over the lease term; and
to combine lease and non-lease components.

8



The Company did not apply the practical expedient to utilize hind-sight in applying the standard. ROU assets represent our right to use an underlying asset for the lease term and lease liabilities represent our obligation to make lease payments arising from the lease, discounted at our annual incremental borrowing rate (“IBR”). ROU assets and liabilities are recognized at the commencement date based on the present value of lease payments over the lease term. Variable lease payments are excluded from the ROU asset and lease liabilities and are recognized in the period in which the obligation for those payments are incurred. For certain leases, where variable lease payments are incurred and relate primarily to common area maintenance, in substance fixed payments are included in the ROU asset and lease liability. For those leases that do not provide an implicit rate, we use our IBR based on the information available at the lease commencement date in determining the present value of lease payments. ROU assets also include any lease payments made and exclude lease incentives. Lease terms do not include options to extend or terminate the lease, as management does not consider them reasonably certain to exercise. The Company has a related party lease, which is included within the ROU asset and liability. Please see Note 14 — Related Party Transactions of the Annual Report for further discussion of the Company’s related parties.
As of January 1, 2019, the Company recognized an operating lease right-of-use asset and corresponding liability of $8.3 million on our condensed consolidated Balance Sheet. See Note 7 — Leases, for further details of the Company’s operating and financing leases.
Recently Issued Accounting Standards
In June 2016, the FASB issued ASU 2016-13, Financial Instruments - Credit Losses, which replaces the incurred loss impairment methodology to reflect expected credit losses. The amendment requires the measurement of all expected credit losses for financial assets held at the reporting date to be performed based on historical experience, current conditions and reasonable and supportable forecasts. ASU 2016-13 is effective for annual and interim periods beginning after December 15, 2019, with early adoption permitted. The Company is evaluating the effect of this accounting standard on its consolidated financial statements.
With the exception of the standard 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.
Note 3 — Acquisitions
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 and equipment. The pro forma results of operations for the MVCI Acquisition is not presented because the pro forma effects, individually and in the aggregate, are not material to the Company’s consolidated results of operations.
Note 4 — Property and Equipment, Net
Property and equipment, net include the following (in millions):
 
 
Estimated Useful Life (years)
 
September 30, 2019
 
December 31, 2018
Machinery and equipment
 
5 - 30
 
$
45.7

 
$
42.0

Vehicles
 
3 - 5
 
20.0

 
17.9

Mechanical refrigeration units
 
30
 
21.9

 
20.9

Natural gas liquid storage tanks
 
15
 
5.9

 
5.9

High specification rigs
 
5 - 20
 
178.8

 
175.7

Other property and equipment
 
3 - 30
 
18.2

 
12.7

Property and equipment
 
 
 
290.5

 
275.1

Less: accumulated depreciation
 
 
 
(77.2
)
 
(52.5
)
Construction in progress
 
 
 
9.5

 
7.2

Property and equipment, net
 
 
 
$
222.8

 
$
229.8

Depreciation expense was $8.9 million and $7.4 million for the three months ended September 30, 2019 and 2018, respectively, and $25.4 million and $20.0 million for the nine months ended September 30, 2019 and 2018, respectively.

9



Note 5 — Goodwill and Intangible Assets
During the year ended December 31, 2018, the Company noted a sustained decrease in the stock price, which was an indication that the fair value of goodwill could have fallen below its carrying amount. As a result, the Company performed a quantitative impairment test and determined the goodwill was impaired. The Company estimated the implied fair value of the goodwill using a variety of valuation methods, including the income and market approaches. During the year ended December 31, 2018, the Company recognized an impairment loss of $9.0 million associated with the remaining balance of our goodwill. The estimated fair value required the use of significant unobservable inputs, representative of a Level 3 fair value measurement.
Definite lived intangible assets are comprised of the following (in millions):
 
 
Estimated Useful Life (years)
 
September 30, 2019
 
December 31, 2018
Tradenames
 
3
 
$
0.1

 
$
0.1

Customer relationships
 
10-18
 
11.4

 
11.4

Less: accumulated amortization
 
 
 
(2.0
)
 
(1.5
)
Intangible assets, net
 
 
 
$
9.5

 
$
10.0

Amortization expense was $0.2 million and $0.1 million for the three months ended September 30, 2019 and 2018, respectively, and $0.5 million and $0.6 million for the nine months ended September 30, 2019 and 2018, respectively. Amortization expense for the future periods is expected to be as follows (in millions):
For the twelve months ending September 30,
 
Amount
2020
 
$
0.7

2021
 
0.7

2022
 
0.7

2023
 
0.7

2024
 
0.8

Thereafter
 
5.9

Total
 
$
9.5

Note 6 — Accrued Expenses
Accrued expenses include the following (in millions):
 
 
September 30, 2019
 
December 31, 2018
Accrued payables
 
$
5.9

 
$
5.6

Accrued compensation
 
14.6

 
6.2

Accrued taxes
 
2.9

 
2.9

Accrued insurance
 
2.4

 
3.8

Accrued expenses
 
$
25.8

 
$
18.5

Note 7 — Leases
Operating Leases
The Company has operating leases, primarily for real estate and equipment, with terms that vary from 12 months to eight years, included in Operating lease costs in the table below. The operating leases are included in Operating lease right-of-use assets, Other current liabilities and Operating lease right-of-use obligations in the Condensed Consolidated Balance Sheet.

10



Lease costs associated with our yards and field offices are included in Cost of Services and our executive offices are included in General and Administrative costs in the Condensed Consolidated Statements of Operations. Lease costs and other information related to operating leases for the three and nine months ended September 30, 2019, is as follows (in millions):
 
 
Three Months Ended
 
Nine Months Ended
 
 
September 30, 2019
Short-term lease costs
 
$
1.1

 
$
4.4

Operating lease cost
 
$
0.9

 
$
2.2

Operating cash outflows from operating leases
 
$
(0.8
)
 
$
(2.2
)
 
 
 
 
 
Weighted average remaining lease term
 
 
 
5.8 years

Weighted average discount rate
 
 
 
9.31
%
Aggregate future minimum lease payments under operating leases are as follows (in millions):
For the twelve months ending September 30,
 
Total
2020
 
$
2.7

2021
 
1.2

2022
 
0.9

2023
 
0.8

2024
 
0.9

Thereafter
 
2.7

Total future minimum lease payments
 
9.2

Less: amount representing interest
 
(2.2
)
Present value of future minimum lease payments
 
7.0

Less: current portion of operating lease obligations
 
(2.2
)
Long-term portion of operating lease obligations
 
$
4.8

Aggregate future minimum rental payments as of December 31, 2018, were as follows (in millions):
For the year ending December 31,
 
Total
2019
 
$
2.9

2020
 
2.3

2021
 
0.9

2022
 
0.7

2023
 
0.7

Thereafter
 
3.0

Total future minimum lease payments
 
$
10.5

Finance Leases
The Company leases certain assets, primarily automobiles, under finance leases which are generally three to five years. The assets and liabilities under finance 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. The finance leases are included in Property and equipment, net, Finance lease obligations, current portion and Finance lease obligations in our Condensed Consolidated Balance Sheet.

11



Lease costs and other information related to finance leases for the three and nine months ended September 30, 2019, is as follows (in millions):
 
 
Three Months Ended
 
Nine Months Ended
 
 
September 30, 2019
Amortization of finance leases
 
$
1.3

 
$
3.8

Interest on lease liabilities
 
$
0.2

 
$
0.6

Financing cash outflows from finance leases
 
$
(1.3
)
 
$
(3.5
)
 
 
 
 
 
Weighted average remaining lease term
 

 
1.6 years

Weighted average discount rate
 

 
4.4
%
Aggregate future minimum lease payments under finance leases are as follows (in millions):
For the twelve months ending September 30,
 
Total
2020
 
$
5.6

2021
 
3.7

2022
 
0.9

2023
 
0.1

2024
 

Thereafter
 

Total future minimum lease payments
 
10.3

Less: amount representing interest
 
(0.7
)
Present value of future minimum lease payments
 
9.6

Less: current portion of finance lease obligations
 
(5.1
)
Long-term portion of finance lease obligations
 
$
4.5

Aggregate future minimum rental payments as of December 31, 2018, were as follows (in millions):
For the year ending December 31,
 
Total
2019
 
$
5.0

2020
 
4.6

2021
 
2.1

2022
 
0.2

2023
 
0.1

Thereafter
 

Total future minimum lease payments
 
12.0

Less: amount representing interest
 
(1.0
)
Present value of future minimum lease payments
 
11.0

Less: current portion of capital lease obligations
 
(4.4
)
Total capital lease obligations, less current portion
 
$
6.6

Note 8 — Debt
The aggregate carrying amounts, net of issuance costs, of the Company’s debt consists of the following (in millions):
 
 
September 30, 2019
 
December 31, 2018
ESCO Notes Payable due February 2019
 
$
5.8

 
$
5.8

Wells Fargo Credit Facility due August 2022
 
17.5

 
17.9

Encina Master Financing Agreement due June 2023
 
29.5

 
36.8

Total Debt
 
52.8

 
60.5

Current portion of long-term debt
 
(15.8
)
 
(15.8
)
Long term-debt, net
 
$
37.0

 
$
44.7


12



ESCO Notes Payable
In connection with the Company’s initial public offering (the “Offering”) and the ESCO Leasing, LLC (“ESCO”) Acquisition, both of which occurred on August 16, 2017, the Company issued $7.0 million of seller’s notes as partial consideration for the ESCO Acquisition. These notes included a note for $1.2 million, which was paid in August 2018 and a note for $5.8 million due in February 2019. Both of these notes bear interest at 5.0% payable quarterly until their respective maturity dates.
During the year ended December 31, 2018, the Company provided notice to ESCO that the Company sought to be indemnified for breach of contract. The Company exercised its right to stop payments of the remaining principal balance of $5.8 million on the Seller’s Notes and any unpaid interest, pending resolution of certain indemnification claims.
Credit Facility
On August 16, 2017, in connection with the Offering, Ranger entered into a $50.0 million senior revolving credit facility (the “Credit Facility”) by and among certain of Ranger’s subsidiaries, as borrowers, each of the lenders party thereto and Wells Fargo Bank, N.A., as administrative agent (the “Administrative Agent”). The Credit Facility is subject to a borrowing base that is calculated based upon a percentage of the value of the Company’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 London Interbank Offering Rate (“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 was 1.75% and the applicable margin for Base Rate loans were 0.75% as of September 30, 2019. During the continuance of a bankruptcy event of default, automatically and during the continuance of any other default, upon the Administrative Agent’s or the required lenders’ election, all outstanding amounts under the Credit Facility bears interest at 2.00% plus the otherwise applicable interest rate. The Credit Facility is scheduled to mature on August 16, 2022 and had a weighted average interest rate of 4.2% as of September 30, 2019.
In addition, the Credit Facility restricts the Company’s ability to make distributions on, or redeem or repurchase, its equity interests, except for certain distributions, including distributions of cash so long as, both at the time of the distribution and after giving effect to the distribution, no default exists under the Credit Facility and either (a) excess availability at all times during the preceding 90 consecutive days, on a pro forma basis and after giving effect to such distribution, is not less than the greater of (1) 22.5% of the lesser of (A) the maximum revolver amount and (B) the then-effective borrowing base and (2) $10.0 million or (b) if the fixed charge coverage ratio is at least 1.0x on a pro forma basis, excess availability at all times during the preceding 90 consecutive days, on a pro forma basis and after giving effect to such distribution, is not less than the greater of (1) 17.5% of the lesser of (A) the maximum revolver amount and (B) the then-effective borrowing base and (2) $7.0 million. If the foregoing threshold under clause (b) is met, the Company may not make such distributions (but may make certain other distributions, including under clause (a) above) prior to the earlier of the date that is (a) 12 months from closing or (b) the date that the Company’s fixed charge coverage ratio is at least 1.0x for two consecutive quarters. The Credit Facility generally permits the Company to make distributions required under the Tax Receivable Agreement (‘‘TRA’’), but a ‘‘Change of Control’’ under the TRA constitutes an event of default under the Credit Facility, and the Credit Facility does not permit the Company to make payments under the TRA upon acceleration of its obligations thereunder unless no event of default exists or would result therefrom and the Company has been in compliance with the fixed charge coverage ratio for the most recent 12-month period on a pro forma basis. The Credit Facility also requires the Company to maintain a fixed charge coverage ratio of at least 1.0x if the Company’s liquidity is less than $10.0 million until the Company’s liquidity is at least $10.0 million for 30 consecutive days. The Company is not to be subject to a fixed charge coverage ratio if it has no drawings under the Credit Facility and has at least $20.0 million of qualified cash.
The Credit Facility contains events of default customary for facilities of this nature, including, but not limited, to:
events of default resulting from the Company’s failure or the failure of any guarantors to comply with covenants and financial ratios;
the occurrence of a change of control;
the institution of insolvency or similar proceedings against the Company or any guarantor; and
the occurrence of a default under any other material indebtedness the Company or any guarantor may have.

13



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, 2019, the Company has borrowed $18.0 million under the Credit Facility. The Company has a borrowing capacity of approximately $35.2 million under the Credit Facility, with approximately $17.2 million available as of September 30, 2019. The Company was in compliance with the Credit Facility covenants as of September 30, 2019.
The Company capitalized fees of $0.7 million associated with the Credit Facility, which are included in the unaudited interim condensed consolidated balance sheets as a discount to the Credit Facility, and will be amortized through maturity. Unamortized debt issuance costs as of September 30, 2019 approximated $0.5 million.
Encina Master Financing and Security Agreement (Financing Agreement)
On June 22, 2018, the Company entered into a Master Financing and Security Agreement with Encina Equipment Finance SPV, LLC (the “Lender”). The amount available to be provided by the Lender to the Company under the Financing Agreement was contemplated to be not less than $35.0 million, and not to exceed $40.0 million. The first financing was required to be in an amount up to $22.0 million, or $21.3 million, net of expenses, which was used by the Company to acquire certain capital equipment. Subsequent to the first financing, the Company borrowed an additional $18.0 million, or $17.8 million, net of expenses, under the Financing Agreement. We utilized the additional net proceeds to acquire certain capital equipment. The Financing Agreement is secured by a lien on certain high-spec rig assets. At September 30, 2019, the aggregate principal balance outstanding was $30.2 million under the Financing Agreement with a weighted average interest rate of 10.2%.
Borrowings under the Financing Agreement bear interest at a rate per annum equal to the sum of 8.0% plus the LIBOR, which was 2.0% as of September 30, 2019. The Financing Agreement requires that the Company maintain leverage ratios of 2.50 to 1.00 as of September 30, 2019 and for periods thereafter. The Company was in compliance with the covenants under the Financing Agreement as of September 30, 2019.
The Company capitalized fees of $0.9 million associated with the Financing Agreement, which are included on the unaudited interim condensed consolidated balance sheets as a discount to the long term debt, and will be amortized through maturity. Unamortized debt issuance costs as of September 30, 2019 approximated $0.7 million.
Scheduled Maturities
As of September 30, 2019, aggregate principal repayments of total debt for the next five years are as follows (in millions):
Twelve months ending September 30,
 
Total
2020
 
$
15.8

2021
 
10.0

2022
 
27.1

2023
 
1.1

Total
 
$
54.0

Note 9—Equity
Equity-Based Compensation
Time-Based Units
During the nine months ended September 30, 2019 and 2018, there were 580,091 and 553,002 restricted shares granted, respectively. The aggregate value of awards granted during nine months ended September 30, 2019 and 2018 was $4.4 million and $4.6 million, respectively. As of September 30, 2019, there was an aggregate $4.9 million of unrecognized expense related to restricted shares issued which is expected to be recognized over a weighted average period of 2.1 years.
Performance Stock Units
During the nine months ended September 30, 2019, the Company granted 105,920 target shares of market based performance restricted stock units at a relative and absolute grant date fair value of approximately $11.96 per share and $9.50 per share, respectively, to certain employees. The market based performance restricted stock units cliff vest on March 21, 2022. As defined in the Long Term Incentive Plan (“LTIP”), the performance criteria applicable to the performance awards is measured at a relative and absolute shareholder return, which measures the Company’s total shareholder return as compared to the total shareholder return of the defined peer group. As of September 30, 2019, there was approximately $0.9 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.

14



During the three and nine months ended September 30, 2018, the Company granted 79,430 target shares of market based performance restricted stock units at a relative and absolute grant date fair value of approximately $8.59 per share and $4.38 per share, respectively, to certain employees. The market based performance restricted stock units cliff vest on December 31, 2020. As defined in the LTIP, the performance criteria applicable to the performance awards is measured at a relative and absolute shareholder return, which measures the Company’s total shareholder return as compared to the total shareholder return of the defined peer group. As of September 30, 2019, there was $0.2 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 1.3 years.
Share Issuance to Related Party
In connection with the Master Reorganization Agreement, an aggregate of $3.0 million (included within other current liabilities on the accompanying consolidated balance sheet as of December 31, 2018) was settled by the Company and CSL Energy Holdings I, LLC and CSL Energy Holdings II, LLC during the nine months ended September 30, 2019. At the Company’s discretion the liability was settled with the issuance of 206,897 Class A Common Stock. Refer to Note 1 — Organization and Business Operations for further details.
Share Repurchase Program
In June 2019, the Board of Directors approved a share repurchase program, authorizing the Company to purchase up to 10% of the outstanding Class A Common Stock held by non-affiliates, not to exceed 580,000 shares or $5.0 million in aggregate value. Share repurchases may take place from time to time on the open market or through privately negotiated transactions. The duration of the share repurchase program is 12 months and may be accelerated, suspended or discontinued at any time without notice. Refer to “Part II, Item 2. Unregistered Sales of Securities” for further information.
Note 10 — Risk Concentrations
Customer Concentrations 
For the three months ended September 30, 2019, two customers, EOG Resources and Concho Resources, Inc., accounted for 19% and 14%, respectively, of the Company’s consolidated revenue. For the nine months ended September 30, 2019, two customers, EOG Resources and Concho Resources, Inc., accounted for 17% and 13%, respectively, of the Company’s consolidated revenues. At September 30, 2019, approximately 25% of the accounts receivable balance was due from these customers.
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 consolidated revenues, respectively. For the nine months ended September 30, 2018, one customer, EOG Resources, accounted for approximately 22%, of the Company’s consolidated revenues. At September 30, 2018, approximately 27% of the accounts receivable balance was due from these customers.
Note 11 — Income Taxes
The Company is a corporation and is subject to U.S. federal income tax. The effective U.S. federal income tax rate applicable to the Company for the nine months ended September 30, 2019 and 2018 was 24.2% and 3.6%, respectively. The Company is subject to the Texas Margin Tax that requires tax payments at a maximum statutory effective rate of 0.75% on the taxable margin of each taxable entity that does business in Texas.
As a result of the Offering and subsequent reorganization, the Company recorded a deferred tax asset; however, a full valuation allowance has been recorded to reduce the Company’s net deferred tax assets to an amount that is more likely than not to be realized and is based upon the uncertainty of the realization of certain federal and state deferred tax assets related to net operating loss carryforwards and other tax attributes. The Company currently believes that it is reasonably possible to achieve a three-year cumulative level of profitability within the next 12 months, and as early as the first quarter of 2020, which would enhance the ability to conclude that is it more likely than not that the deferred tax assets would be realized and support a release of a portion or substantially all of the valuation allowance. A release of the valuation allowance would result in the recognition of an increase in deferred tax assets and an income tax benefit in the period in which the release occurs, although the exact timing and amount of the release is subject to change based on numerous factors, including projections of future taxable income, which continues to be assessed based on available information each reporting period.
Total income tax expense for the three and nine months ended September 30, 2019 differed from amounts computed by applying the U.S. federal statutory tax rates to pre-tax income primarily due to the release of the valuation allowance related to current period pre-tax book income and the impact of permanent differences between book and taxable income attributable to non-controlling interest. The effective tax rate includes a rate benefit attributable to the fact that Ranger LLC operates as a limited liability company treated as a partnership for federal and state income tax purposes and as such, is not subject to federal and state income taxes, except for the State of Texas for which Ranger LLC files with the Company. Accordingly, the portion of earnings attributable to non-controlling interest is subject to tax when reported as a component of the non-controlling interest’s taxable income.

15



The Company is subject to the following material taxing jurisdictions: the United States and Texas. As of September 30, 2019, the Company has no current tax years under audit. The Company remains subject to examination for federal income taxes and state income taxes for tax years 2017 and 2016.
The Company has evaluated all tax positions for which the statute of limitations remains open and believes that the material positions taken would more likely than not be sustained upon examination. Therefore, as of September 30, 2019, the Company had not established any reserves for, nor recorded any unrecognized benefits related to, uncertain tax positions.
Note 12 — 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.
 
 
Three Months Ended
 
Nine Months Ended
 
 
September 30,
 
September 30,
 
 
2019
 
2018
 
2019
 
2018
Income (loss) (numerator):
 
 
 
 
 
 
 
 
Basic:
 
 
 
 
 
 
 
 
Net income (loss) attributable to Ranger Energy Services, Inc.
 
$
(0.5
)
 
$
2.1

 
$
2.5

 
$
(4.3
)
Less: Undistributed earnings allocable to Class B Common Stock
 

 

 

 

Net income (loss) attributable to Class A Common Stock
 
$
(0.5
)
 
$
2.1

 
$
2.5

 
$
(4.3
)
 
 
 
 
 
 
 
 
 
Diluted:
 
 
 
 
 
 
 
 
Net income (loss) attributable to Ranger Energy Services, Inc.
 
$
(0.5
)
 
$
2.1

 
$
2.5

 
$
(4.3
)
Less: Undistributed earnings allocable to Class B Common Stock
 

 

 

 

Net income (loss) attributable to Class A Common Stock
 
$
(0.5
)
 
$
2.1

 
$
2.5

 
$
(4.3
)
 
 
 
 
 
 
 
 
 
Weighted average shares (denominator):
 
 
 
 
 
 
 
 
Weighted average number of shares - basic
 
8,769,389

 
8,428,271

 
8,591,128

 
8,418,607

Weighted average number of shares - diluted
 
8,769,389

 
8,674,883

 
9,459,786

 
8,418,607

 
 
 
 
 
 
 
 
 
Basic income (loss) per share
 
$
(0.06
)
 
$
0.25

 
$
0.29

 
$
(0.51
)
Diluted income (loss) per share
 
$
(0.06
)
 
$
0.24

 
$
0.26

 
$
(0.51
)
During the three and nine months ended September 30, 2019 and 2018, the Company excluded 6.9 million shares of Common Stock issuable upon conversion of the Company’s Class B Common Stock in calculating diluted earnings (loss) per share, as the effect was anti-dilutive. During the three months ended September 30, 2019, the Company excluded 0.9 million equity-based compensation awards in calculating diluted loss per share, as the effect was anti-dilutive. During the nine months ended September 30, 2018, the Company excluded 0.5 million equity-based compensation awards in calculating diluted loss per share, as the effect was anti-dilutive.
Note 13 — Commitments 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.
During the year ended December 31, 2018, the Company provided notice to ESCO that the Company sought to be indemnified for breach of contract. The Company exercised the right to stop payments of the remaining principal balance of $5.8 million on the Seller's Notes and any unpaid interest, pending resolution of certain indemnification claims.
Note 14 — Segment Reporting
Historically, the Company reported two segments, with corporate general and administrative expense categorized as other. During the fourth quarter of 2018, the Company bifurcated the legacy Well Services segment into High Specification Rigs and Completion and Other Services due to the modifications made to its internal reporting and responsibilities of those reporting to the Chief Operating Decision Maker (“CODM”). As a result, the financial information being provided to the CODM has been updated to align with our new internal organization, which resulted in a new reportable segment discussed further below.

16



The Company’s operations are all located in the United States and organized into three reportable segments: High Specification Rigs, Completion and Other Services and Processing Solutions. Our reportable segments comprise the structure used by our CODM to make key operating decisions and assess performance during the years presented in the accompanying condensed consolidated financial statements. Our CODM evaluates the segments’ operating performance based on multiple measures including Operating income (loss), Adjusted EBITDA, rig hours and rig utilization. The tables below present the operating income (loss) measurement, as the Company believes this is most consistent with the principals used in measuring the condensed consolidated financial statements.
We have made certain reclassifications to our prior period operating revenue, cost of sales and general and administrative amounts due to the change in reportable segments whereby our High Specification Rig and Completion and Other Services segments were bifurcated from our legacy Well Services segment as a result of our fourth quarter 2018 operating segment changes. None of these reclassifications have an impact on our condensed consolidated operations results, cash flows or financial position.
The following is a description of each operating segment:
High Specification Rigs.  The Company’s High Specification Rigs facilitate operations throughout the lifecycle of a well, including (i) completion, (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. Our high-spec rigs are designed to support growing U.S. horizontal well demands.
Completion and Other Services.  Our Completion and Other Services segment provides services necessary to bring and maintain a well on production and consists primarily of our wireline and snubbing lines of business along with other, non-rig well services, such as fluid management and well services-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 any 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.
Segment information as of September 30, 2019 and December 31, 2018 and for the three and nine months ended September 30, 2019 and 2018 is as follows (in millions):
 
 
Three months ended September 30, 2019
 
 
High Specification Rigs
 
Completion and Other Services
 
Processing Solutions
 
Other
 
Total
Revenues
 
$
32.5

 
$
45.3

 
$
6.3

 
$

 
$
84.1

Cost of services
 
29.3

 
34.6

 
2.8

 

 
66.7

Depreciation and amortization
 
5.3

 
2.9

 
0.6

 
0.3

 
9.1

Operating income (loss)
 
(2.1
)
 
7.8

 
2.9

 
(7.0
)
 
1.6

Interest expense, net
 

 

 

 
1.4

 
1.4

Net income (loss)
 
(2.1
)
 
7.8

 
2.9

 
(9.5
)
 
(0.9
)
Capital expenditures
 
$
2.3

 
$
0.2

 
$
1.2

 
$

 
$
3.7

 
 
Nine months ended September 30, 2019
Revenues
 
$
97.3

 
$
143.2

 
$
16.2

 
$

 
$
256.7

Cost of services
 
85.4

 
107.5

 
6.9

 

 
199.8

Depreciation and amortization
 
14.9

 
8.6

 
1.6

 
0.8

 
25.9

Operating income (loss)
 
(3.0
)
 
27.1

 
7.7

 
(21.0
)
 
10.8

Interest expense, net
 

 

 

 
4.6

 
4.6

Net income (loss)
 
(3.0
)
 
27.1

 
7.7

 
(27.3
)
 
4.5

Capital expenditures
 
$
6.3

 
$
3.8

 
$
7.7

 
$
0.5

 
$
18.3

 
 
As of September 30, 2019
Property and equipment, net
 
$
132.6

 
$
44.3

 
$
40.4

 
$
5.5

 
222.8

Total assets
 
$
190.7

 
$
63.8

 
$
46.0

 
$
7.9

 
$
308.4


17



 
 
Three Months Ended September 30, 2018
 
 
High Specification Rigs
 
Completion and Other Services
 
Processing Solutions
 
Other
 
Total
Revenues
 
$
38.7

 
$
39.4

 
$
4.0

 
$

 
$
82.1

Cost of services
 
33.2

 
28.0

 
1.8

 

 
63.0

Depreciation and amortization
 
4.6

 
2.2

 
0.5

 
0.2

 
7.5

Impairment of goodwill
 

 

 

 

 

Operating income (loss)
 
0.9

 
9.2

 
1.7

 
(7.4
)
 
4.4

Interest expense, net
 

 

 

 
0.9

 
0.9

Net income (loss)
 
0.9

 
9.2

 
1.7

 
(7.8
)
 
4.0

Capital expenditures
 
$
16.4

 
$
3.6

 
$
2.0

 
$

 
$
22.0

 
 
Nine Months Ended September 30, 2018
Revenues
 
$
114.6

 
$
92.3

 
$
10.9

 
$

 
$
217.8

Cost of services
 
98.3

 
68.2

 
5.1

 

 
171.6

Depreciation and amortization
 
13.2

 
5.7

 
1.1

 
0.6

 
20.6

Impairment of goodwill
 
9.0

 

 

 

 
9.0

Operating income (loss)
 
(5.9
)
 
18.4

 
4.7

 
(22.6
)
 
(5.4
)
Interest expense, net
 

 

 

 
1.8

 
1.8

Net income (loss)
 
(5.9
)
 
18.4

 
4.7

 
(24.7
)
 
(7.5
)
Capital expenditures
 
$
41.4

 
$
9.1

 
$
5.1

 
$
0.5

 
$
56.1

 
 
As of December 31, 2018
Property and equipment, net
 
$
159.2

 
$
35.0

 
$
34.3

 
$
1.3

 
$
229.8

Total assets
 
$
214.1

 
$
47.0

 
$
40.1

 
$
1.3

 
$
302.5


18



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 filed on Form 10-K for the years ended December 31, 2018 and 2017. We assume no obligation to update any of these forward‑looking statements.
Overview
The Company is one of the largest providers of high‑spec well service rigs and associated services in the United States, with a focus on technically demanding unconventional horizontal well completion and production operations. We believe that our fleet of 139 well service rigs is among the newest and most advanced in the industry and, based on our historical rig utilization and feedback from our customers, we believe that we are an operator of choice for U.S. onshore exploration and production (“E&P”) companies that require completion and production services at increasing lateral lengths. 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 and Sooner Trend Anadarko Basin Canadian and Kingfisher counties plays.
We conduct our operations through three segments: High Specification Rigs, Completion and Other Services and Processing Solutions, as described below.
Our High Specification Rig Services segment provides well service rigs and complementary equipment and services in the United States, with a focus on technically demanding unconventional horizontal well completion, workover and maintenance operations. These services are fundamental to establishing and maintaining the flow of oil and natural gas throughout the productive life of a well. Our high‑specification well service rigs facilitate operations throughout the lifecycle of a well, including (i) completion services, such as milling out composite plugs after the hydraulic fracturing process and the installation of downhole production equipment; (ii) workover, including retrieval and replacement of existing production tubing; (iii) well maintenance, including replacement of downhole artificial lift components; and (iv) decommissioning, such as plugging and abandonment operations.
Our Completion and Other Services segment provides services necessary to bring and maintain a well on production and primarily includes (i) wireline perforating and pumpdown services and (ii) snubbing services often utilized in conjunction with our high-spec rigs to convey equipment in and out of a well during completion and workover activities. The Company provides rental equipment, including well control packages, hydraulic catwalks and other equipment that is often deployed with our well service rigs.
Our Processing Solutions segment engages in the rental, installation, commissioning, start‑up, operation and maintenance of Mechanical Refrigeration Units (“MRU”), Natural Gas Liquid (“NGL”) stabilizer units, NGL storage units and related equipment. 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.
For further information regarding the results of operations for each segment, please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Results of Operations” in Item 2 and Part I of this Quarterly Report.
How We Generate Revenues
We currently generate revenues through the provision of a variety of oilfield services. These services are performed under a variety of contract structures, including a long term take‑or‑pay contract and various master service agreements, as supplemented by statements of work, pricing agreements and specific quotes. A portion of our master services agreements include provisions that establish pricing arrangements for a period of up to one year in length. However, the majority of those agreements provide for pricing adjustments based on market conditions. The majority of our services are priced based on prevailing market conditions and changing input costs at the time the services are provided, giving consideration to the specific requirements of the customer.
In determining the appropriate amount of revenue to be recognized as we fulfill the obligations under its contracts with customers, the following steps must be performed at contract inception: (i) identification of the promised goods or services in the contract; (ii) determination of whether the promised goods or services are performance obligations, including whether they are

19



distinct in the context of the contract; (iii) measurement of the transaction price, including the constraint on variable consideration; (iv) allocation of the transaction price to the performance obligation and (v) recognition of revenue when (or as) the Company satisfies each performance obligation.
We satisfy our performance obligation over time as the services are performed. The Company believes the output method is a reasonable measure of progress for the satisfaction of our performance obligations, which are satisfied over time, as it provides a faithful depiction of (i) our performance towards complete satisfaction of the performance obligation under the contract and (ii) the value transferred to the customer of the services performed under the contract. We invoice our customers upon completion of the specified services and collection generally occurs within the payment terms agreed with customers. Accordingly, there is no financing component to our arrangement with customers. Please see Note 2 — Summary of Significant Accounting Policies of the Annual Report.
Costs of Conducting Our Business
The principal expenses involved in conducting our business are personnel, repairs and maintenance costs, general and administrative, depreciation and amortization and interest expense. We manage the level of our expenses, except depreciation and amortization and interest expense, based on several factors, including industry conditions and expected demand for our services. In addition, a significant portion of the costs we incur in our business is variable based on the quantities of specific services provided and the requirements of such services.
Direct cost of services and general and administrative expenses include the following major cost categories: personnel costs and equipment costs (including repair and maintenance).
Personnel costs associated with our operational employees represent a significant cost of our business. A substantial portion of our labor costs is attributable to our crews and is partly variable based on the requirements of specific customers and operations. A key component of personnel costs relates to the ongoing training of our employees, which improves safety rates and reduces attrition. We also incur costs to employ personnel to support our services and perform maintenance on our assets. Costs for these employees are not directly tied to our level of business activity.
We incur significant equipment costs in connection with the operation of our business, including repair and maintenance costs.
How We Evaluate Our Operations
Management uses a variety of metrics to analyze our operating results and profitability. These metrics include, among others, operating revenues, operating income (loss) and Adjusted EBITDA.
Within our High Specification Rig segment, management uses additional metrics to analyze our activity levels and profitability. These metrics include, among others, rig hours and 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 or benefit, depreciation and amortization, equity‑based compensation, acquisition‑related and severance costs, impairment of goodwill, gain or loss on disposal of assets and other non-cash and certain 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.

20



Rig Hours
Within our High Specification Rig segment, we analyze rig hours as an important indicator of our activity levels and profitability. Rig hours represent the aggregate number of hours that our well service rigs actively worked during the periods presented. We typically bill customers for our well services on an hourly basis during the period that a well service rig is actively working, making rig hours a useful metric for evaluating our profitability.
Rig Utilization
Within our High Specification Rig segment, we analyze rig utilization as a further important indicator of our activity levels and profitability. We measure rig utilization by reference to average monthly hours per rig, which is calculated by dividing (a) the approximate, aggregate operating well service rig hours for the periods presented by (b) the aggregate number of high-spec rigs in our fleet during such period, as aggregated on a monthly basis utilizing a mid-month convention whereby a high-spec rig added to our fleet during a month, meaning that we have taken delivery of such high-spec rig and it is ready for service, assumed to be in our fleet for one half of such month. We believe that rig utilization as measured by average monthly hours per high-spec 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 high-spec 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 three months ended September 30, 2019 and 2018, our rig utilization as measured by average monthly hours per rig was approximately 149 hours and 178 hours, respectively. Actual aggregate operating well service rig hours decreased from approximately 74,200 in the three months ended September 30, 2018 to approximately 62,400 for the three months ended September 30, 2019. Our average revenue per rig hour remained constant at $519 for both the three months ended September 30, 2019 and 2018.
For the nine months ended September 30, 2019 and 2018, our rig utilization, as measured by average monthly hours per rig, was approximately 146 hours and 183 hours, respectively. Actual aggregate operating well service rig hours decreased from approximately 224,600 in the nine months ended September 30, 2018, to approximately 184,700 in the nine months ended September 30, 2019. The decrease in rig hours was partially offset by an increase in our average revenue per rig hour to $524 from $505 for the nine months ended September 30, 2019 and 2018, respectively.
Factors Impacting the Comparability of Results of Operations
Tax Receivable Agreement
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 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. 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. We currently believe that it is

21



reasonably possible for us to achieve a three-year cumulative level of profitability within the next 12 months, and as early as the first quarter of 2020, which would enhance our ability to conclude that it is more likely than not that the deferred tax assets would be realized and support a release of a portion or substantially all of the valuation allowance. A release of the valuation allowance would result in the recognition of an increase in deferred tax assets and an income tax benefit in the period in which the release occurs, although the exact timing and amount of the release is subject to change based on numerous factors, including our projections of future taxable income, which we continue to assess based on available information each reporting period.
Results of Operations
Three Months Ended September 30, 2019 compared to Three Months Ended September 30, 2018
The following table presents the operating results for the three months ended September 30, 2019 as compared to the three months ended September 30, 2018.
 
 
Three Months Ended
 
 
 
 
 
 
September 30,
 
Change
 
 
2019
 
2018
 
$
 
%
Revenues
 
 
 
 
 
 
 
 
High Specification Rigs
 
$
32.5

 
$
38.7

 
$
(6.2
)
 
(16
)%
Completion and Other Services
 
45.3

 
39.4

 
5.9

 
15
 %
Processing Solutions
 
6.3

 
4.0

 
2.3

 
58
 %
Total revenues
 
84.1

 
82.1

 
2.0

 
2
 %
Operating expenses
 
 
 
 
 
 
 
 
Cost of services (exclusive of depreciation and amortization shown separately):
 
 
 
 
 
 
 
 
High Specification Rigs
 
29.3