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EX-23.1 - EX-23.1 - Ranger Energy Services, Inc.rngr-20171231ex231e98aab.htm
EX-21.1 - EX-21.1 - Ranger Energy Services, Inc.rngr-20171231ex211c3d82a.htm

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10‑K

ANNUAL REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2017

OR

¨

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

For the transition period from to

Commission file number 001-38183

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

(713) 935‑8900

(Address, Including Zip Code, and Telephone Number, Including Area Code, of Registrant’s Principal Executive Offices)

 

Securities registered pursuant to Section 12(b) of the Act:

 

 

 

Title of each class

 

Name of each exchange on which registered

Class A Common Stock, $0.01 par value

 

New York Stock Exchange

Indicate by check mark if the Registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes No

Indicate by check mark if the Registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes No

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 and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted 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 and post such files). Yes No

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of Registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10 K

Indicate by check mark whether the Registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, 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. (Check one):

 

Large accelerated filer 

 

Accelerated filer   

 

 

 

 

Non-accelerated filer 

 

Smaller reporting company 

 

(Do not check if a 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 June 30, 2017, the last business day of Registrant’s most recently completed second fiscal quarter, the Registrant’s Class A Common Stock was not listed on a domestic exchange or over-the-counter market. The Registrant’s Class A Common Stock began trading on the New York Stock Exchange on August 10, 2017.

At February 21, 2018, the Registrant had 8,413,178 shares of Class A Common Stock and 6,866,154 shares of Class B Common Stock outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant’s definitive proxy statement for the 2018 Annual Meeting of Stockholders, to be filed no later than 120 days after the end of the fiscal year to which this Annual Report on Form 10-K relates, are incorporated by reference into Part III of this Annual Report on Form 10-K.

 

 


 

RANGER ENERGY SERVICES, INC.

TABLE OF CONTENTS

 

 

 

 

 

 

Page

 

 

 

Cautionary Statement 

 

 

 

 

 

PART I 

 

 

Item 1. Business 

 

1

Item 1A. Risk Factors 

 

13

Item 1B. Unresolved Staff Comments 

 

38

Item 2. Properties 

 

38

Item 3. Legal Proceedings 

 

40

Item 4. Mine Safety Disclosures 

 

40

 

 

 

PART II 

 

 

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities 

 

41

Item 6. Selected Financial Data 

 

43

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations 

 

44

Item 7A. Quantitative and Qualitative Disclosures About Market Risk 

 

62

Item 8. Financial Statements and Supplementary Data 

 

63

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosures 

 

63

Item 9A. Controls and Procedures 

 

64

Item 9B. Other Information 

 

64

PART III 

 

 

Item 10. Director, Executive Officers and Corporate Governance 

 

65

Item 11. Executive Compensation 

 

65

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters 

 

65

Item 13. Certain Relationship and Related Transactions, and Director Independence 

 

65

Item 14. Principal Accounting Fees and Services 

 

65

PART IV 

 

 

Item 15. Exhibits, Financial Statement Schedules 

 

65

Item 16. Form 10-K Summary 

 

67

SIGNATURES 

 

68

 

 

 

Consolidated Financial Statements 

 

69

 

 


 

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

The information in this Annual Report on Form 10-K (“Annual Report”) includes “forward‑looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended and Section 21E of the Exchange Act of 1934, as amended. All statements, other than statements of historical fact included in this Form 10-K, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward‑looking statements. When used in this Form 10-K, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project” and similar expressions are intended to identify forward‑looking statements, although not all forward‑looking statements contain such identifying words. These forward‑looking statements are based on our current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events.

Forward‑looking statements may include statements about:

·

our business strategy;

·

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

·

our future revenue, income and operating performance;

·

our ability to sustain and improve our utilization, revenues and margins;

·

our ability to maintain acceptable pricing for our services;

·

our future capital expenditures;

·

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

·

competition and government regulations;

·

our ability to obtain permits and governmental approvals;

·

pending legal or environmental matters;

·

marketing of oil and natural gas;

·

business or asset acquisitions, including the ESCO Acquisition;

·

general economic conditions;

·

credit markets;

·

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

·

uncertainty regarding our future operating results; and

·

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

We caution you that these forward‑looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control. These risks include, but are not limited to, the risks described under “Risk Factors” in this Annual Report. Should one or more of the risks or uncertainties described occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward‑looking statements.

All forward‑looking statements, expressed or implied, included in this Annual Report are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward‑looking statements that we or persons acting on our behalf may issue. Except as otherwise required by applicable law, we disclaim any duty to update any forward‑looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this Annual Report.

 

 

 

 


 

 

 

PART I

Except as otherwise indicated or required by the context, all references in this Annual Report to the “Company,” “Ranger,” “we,” “us” or “our” relate, prior to our initial public offering (the “Offering”), to Ranger Energy Services, LLC (“Ranger Services”) and Torrent Energy Services, LLC (“Torrent Services”) on a combined basis (as combined, our “Predecessor,” and each, a “Predecessor Company”), and following the Offering, to Ranger Energy Services, Inc. (“Ranger Inc.”) and its consolidated subsidiaries. References in this Annual Report to “Ranger LLC” refer to RNGR Energy Services, LLC, which owns our operating subsidiaries, including Ranger Services and Torrent Services. References in this Annual Report to the “Existing Owners” refer to Ranger Energy Holdings, LLC (“Ranger Holdings”), Ranger Energy Holdings II, LLC (“Ranger Holdings II”), Torrent Energy Holdings, LLC (“Torrent Holdings”) and Torrent Energy Holdings II, LLC (“Torrent Holdings II”), the entities through which our legacy investors, including CSL Capital Management, LLC (“CSL”) , certain members of our management and other investors own their retained interest in us and Ranger LLC.

A reference to a “Note” herein refers to the accompanying “Notes to the Consolidated Financial Statements” contained in “Financial Statements and Supplementary Data” in Item 8 of this Annual Report. In addition, please read “Cautionary Statement Regarding Forward-Looking Statements” and “Risk Factors” in Item 1A for information regarding certain risks inherent in our business.

 

ITEM 1. BUSINESS

Our Company

We are 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 135 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) 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. 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, the Gulf Coast and the SCOOP and STACK plays.

We have invested in a premier fleet of well service rigs. Our customers, which include many of the leading U.S. onshore E&P operators such as Devon Energy Corporation, EOG Resources, Inc., Noble Energy, Inc., Oasis Petroleum Inc., PDC Energy Inc. and Statoil ASA, are increasingly utilizing modern horizontal well designs characterized by long lateral lengths that can extend in excess of 12,000 feet. Long lateral length wellbores require increased amounts of completion tubing, which, in turn, require well service rigs with higher operating horsepower (“HP”) to pull longer tubing strings from the wellbore. Furthermore, long lateral horizontal wells generally utilize taller stacks of wellhead equipment, which drives demand for well service rigs that have taller mast heights capable of accommodating an elevated work floor. These modern horizontal well designs are ideally serviced by “high‑spec” well service rigs with high operating HP (450 HP or greater) and tall mast heights (102 feet or higher) rather than competing coiled tubing units and older or lower‑spec well service rigs. As of December 31, 2017, all but one of our well service rigs meets these specifications, and approximately 82% of our well service rigs exceed these specifications with HP ratings of at least 500 HP and mast heights of at least 104 feet, making our fleet particularly well‑suited to perform high‑margin, horizontal well completion and production operations. The only remaining rig in our fleet is generally deployed only for plugging and abandonment operations of conventional vertical wells.

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The high‑spec well service rigs in our fleet, a substantial majority of which has been built since 2010, have an average age of approximately six years and feature modern operating components sourced from leading U.S. manufacturers such as National Oilwell Varco, Inc. (“NOV”). In February 2017, to meet expected customer demand, we entered into a purchase agreement with NOV (the “NOV Purchase Agreement”), pursuant to which we expect to accept delivery of an additional 9 high‑spec well service rigs periodically in 2018. As of December 31, 2017, we had accepted delivery of 16 high-spec well service rigs from NOV. However, NOV is not obligated pursuant to the NOV Purchase Agreement to deliver high‑spec well service rigs during 2018, and will not face penalties for delayed delivery, regardless of the length or cause of any delay. Following delivery of the rigs pursuant to the NOV Purchase Agreement, our well service rig fleet will expand to 144 rigs, 143 of which will be high‑spec. The following table provides summary information regarding our high‑spec well service rig fleet, including the additional rigs that we expect to be delivered during the remainder of 2018. For additional information, please see “Properties and Equipment—Equipment—Well Services” in Item 2 of this Annual Report.

 

 

 

 

 

HP Rating(1)

Mast Height

Mast Rating(2)

Manufacturer & Model

Number of High‑Spec Rigs

600 HP.........................

112’ ‑ 117’

 

 

 

 

 

300,000 ‑ 350,000 lbs

 

 

 

 

 

NOV 6‑C

 

 

 

 

 

13*

 

 

 

 

500 ‑ 550 HP.................

104’ ‑ 108’

 

 

 

250,000 ‑ 275,000 lbs

 

 

 

NOV 5‑C and equivalent

 

 

105**

 

 

 

450 ‑ 475 HP.................

102’ ‑ 104’

 

 

200,000 ‑ 250,000 lbs

 

 

NOV 4‑C and equivalent

 

25***

 

 

Total.............................

 

 

 

143

 


(1)Per manufacturer.

(2)The mast ratings of our high‑spec well service rigs complement their high operating HP and tall mast heights by allowing such rigs to safely support the higher weights associated with the long tubing strings used in long‑lateral well completion operations.

*Includes one rig expected to be delivered during 2018.

**Includes six rigs expected to be delivered during 2018.

***Includes two rigs expected to be delivered during 2018.

The composition of our well service rig fleet makes it particularly well‑suited to provide both completion‑oriented services, the demand for which generally increases along with increased capital spending by E&P operators, and production‑oriented services, the demand for which is less influenced, on a comparative basis, by such capital spending. The ability of our well service rigs to accommodate the needs of our E&P customers in a variety of economic conditions has historically allowed us to maintain relatively high rig utilization as measured by total monthly rig hours worked in a particular period per well service rig, which we refer to herein as our average monthly hours per rig. For example, our rig utilization as measured by average monthly hours per rig (and discussed further in “Management’s Discussion and Analysis of Financial Condition and Results of Operations—How We Evaluate Our Operations—Rig Utilization”), exclusive of the impact of the acquisition (the “ESCO Acquisition”) of certain assets from ESCO Leasing, LLC, an affiliate of Energy Services Company of Bowie, Inc. (“ESCO”), during 2017, 2016, and 2015 was approximately 211, 178, and 193, respectively, which we believe to be significantly higher than that of our publicly listed competitors in the United States over such periods. Our rig utilization inclusive of ESCO for August 16, 2017 through December 31, 2017 was 194.

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In addition to our core well service rig operations, we offer a suite of complementary services, including wireline, snubbing, fluid management and well service‑related equipment rentals. Our rental equipment includes well control packages and hydraulic catwalks, which are typically deployed in conjunction with high‑spec well service rigs. These complementary services and equipment are typically procured by the same decision‑makers as our customers that procure our well service rigs and are provided by our same field personnel, generating incremental revenues per job while limiting incremental costs to us. Our complementary well completion and production services and equipment strategically enhance our operating footprint, create operational efficiencies for our customers and allow us to capture a greater portion of their spending across the lifecycle of a well.

We also provide 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. Our fleet of more than 25 mechanical refrigeration units (“MRUs”) is modern, reliable and equipped to handle large volumes of natural gas from conventional and unconventional wells while operating across a broad array of oilfield conditions with minimal downtime and maintenance. Our customers rely on our purpose‑built MRUs to process natural gas to meet pipeline specifications, extract higher value natural gas liquids (“NGLs”), process natural gas to conform to the specifications of fuel gas that can be used at well sites and facilities, and to reduce the amount of hydrocarbons at the flare tip to control emissions of hazardous volatile organic compounds (“VOCs”).

We have focused on combining our high‑spec rig fleet, complementary well service operations and processing solutions with a highly skilled and experienced workforce, which enables us to consistently and efficiently deliver exceptional service while maintaining high health, safety and environmental standards. We believe that our strong operational performance and safety record provides a strong competitive advantage with current and prospective E&P customers.

Organization

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 acquired by CSL through Torrent Holdings 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. The consolidated financial information in this Annual Report includes, as applicable, the results of operations of Magna and Bayou for periods subsequent to their respective acquisitions.

We were incorporated as a Delaware corporation in February 2017. In conjunction with 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 elsewhere in this Annual Report,  we  became a holding company, the sole material assets of which consist of membership interests in 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 the 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.

3


 

The following diagram indicates our current ownership structure as a result of the Offering and the transactions related thereto:

Organization

Picture 3

(1)      CSL, certain members of our management and other investors own all of the equity interests in the Existing Owners, and CSL holds a majority of the voting interests in each of the Existing Owners.

(2)      Includes 344,828 shares of Class A Common Stock issued to ESCO in connection with the ESCO Acquisition.

(3)      Includes CSL Energy Opportunities Fund II, L.P. (“CSL Opportunities II”), CSL Energy Holdings II, LLC (“CSL Holdings II”) and Bayou Well Holdings Company, LLC (“Bayou Holdings”).

(4)      Includes Ranger Services and Torrent Services.

(5)      Totals may not sum or recalculate due to rounding.

 

Our Segments

We conduct our operations through two segments: Well Services and  Processing Solutions. 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 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. We incurs costs that are not specific to either of the operating segments, mainly from internal services providing a corporate and administrative function, these are reported as other.  For further information regarding the results of operations for each segment, please see Item 7 and Note 19 – Segment Reporting.  

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Well Services

Our high‑spec well service rigs facilitate operations throughout the lifecycle of a well, including, as described in greater detail below, (i) well completion support; (ii) workover; (iii) well maintenance; and (iv) decommissioning. We provide these advanced well services to E&P companies, particularly to those operating in unconventional oil and natural gas reservoirs and requiring technically and operationally advanced services. Our high‑spec well service rigs are designed to support growing U.S. horizontal well demands.

Specifically, our well service rig operations consist primarily of the following:

Well completion support. Our well completion support services are utilized subsequent to hydraulic fracturing operations but prior to placing a well into production, and primarily include unconventional well completion operations, including milling out composite plugs, frac sand or other downhole debris or obstructions that were introduced in the well as part of the completion process and installing production tubing and other permanent downhole equipment necessary to facilitate extraction and production.

Workovers. Our workover services primarily facilitate major well repairs or modifications required to sustain the flow of oil and natural gas in a producing well. Workovers, which may require a few days to several weeks to complete and generally require additional auxiliary equipment, are typically more complex and more time consuming than well maintenance operations. Workover operations include major subsurface repairs such as repair or replacement of well casing, recovery or replacement of tubing and removal of foreign objects from the wellbore. All of our high‑spec well service rigs are designed to perform complex workover operations.

Well maintenance. Our well maintenance services, which are generally conducted multiple times throughout the life of a well, provide periodic maintenance required throughout the life of a well to sustain optimal levels of oil and natural gas production. Our well maintenance services primarily include the removal and replacement of downhole production equipment, including artificial lift components such as sucker rods and downhole pumps, the repair of failed production tubing and the repair and removal of other downhole production‑related byproducts such as frac sand or paraffin that impair well productivity. These and similar routine maintenance services involve relatively low‑cost, short‑duration operations that generally experience relatively stable demand notwithstanding changes in drilling activity.

Decommissioning. Our decommissioning services primarily include plugging and abandonment, in which our well service rigs and wireline and cementing equipment are used to prepare non‑economic oil and natural gas wells to be shut in and permanently or temporarily sealed. Decommissioning work is typically less sensitive to oil and natural gas prices than our other well service rig operations as a result of decommissioning obligations imposed by state regulations.

In addition to our core well service rig operations, we also offer a suite of complementary services, including well service‑related equipment rentals, wireline, snubbing and fluid management services.

Well Service‑Related Equipment Rentals. Our well service‑related equipment rentals consist of a diverse fleet of rental items, including power swivels (hydraulic motor‑driven, pipe‑rotating machines used to deliver shock‑free torque to the drillstring or tubing during well service rig operations), well control packages (equipment used to ensure formation pressure is maintained within the wellbore during well service rig operations), hydraulic catwalks (mechanized lifting devices used to raise and lower drill pipe and tubing to and from the well service rig work floor), frac tanks, pipe racks and pipe handling tools. Our well service‑related equipment rentals are typically used in conjunction with the services provided by our well service rigs and, in the last several years, have resulted in incremental associated revenues and enhanced profit margins.

Wireline Services. Our wireline services involve the use of wireline trucks equipped with a spool of cable that is unwound and lowered into oil and natural gas wells to convey specialized tools or equipment for well completion, well intervention, pipe recovery, plugging and abandonment and reservoir evaluation purposes.

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Snubbing Services. Our snubbing services consist of using our snubbing units together with our well service rigs in order to perform well maintenance or workover operations on a pressurized well without killing the well. Our snubbing services, which enable operators to safely run or remove pipe and other associated downhole tools into a flowing well, are utilized for well maintenance, workover and well completion activities.

Fluid Management Services. Our fluid management services consist of the hauling of oilfield fluids, including drilling mud, fresh water and saltwater used or produced in well drilling, completion and production. Additionally, we rent tanks to store such fluids at the wellsite.

Processing Solutions

In our processing solutions segment, we provide 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. We have developed a premium offering that includes proprietary designs on modern processing equipment, including modular MRUs. Our modular units provide flexibility across a broad range of project requirements and operating environments, and are designed to allow for quick mobilization to minimize downtime and increase utilization, particularly in conjunction with the operational support provided by our expert field personnel. Our natural gas processing solutions assist our customers with meeting pipeline specifications, extracting higher value NGLs, providing fuel gas for wellsites and facilities and reducing emissions at the flare tip. Our modular units provide flexibility to match a broad range of project requirements and are designed to allow for quick mobilization and demobilization.

In addition to our proprietary natural gas and NGL processing equipment, we offer full transportation, installation and ongoing operation services in the field. Our turn‑key mobilization services include in‑bound transportation, site offloading, installation, commissioning, startup and training of field personnel. Our ongoing operations and maintenance services include daily onsite and callout service, daily field reports and NGL transportation and marketing arrangements. We also employ full‑time process and mechanical engineers with significant experience in designing gas treating and processing solutions to provide quality service to our customers.

Competition

The markets in which we operate are highly competitive. We provide services in various geographic regions across the United States, and our competitors include many large and small oilfield service providers, including some of the largest integrated service companies. Specifically, our primary competitors in the well services market include Basic Energy Services, Inc., C&J Energy Services, Inc., Forbes Energy Services Ltd., Key Energy Services Inc., Nine Energy Service Inc. and Pioneer Energy Services Corp. We view Pioneer Energy Services as our most significant competitor in the high-spec well service rig market. In the processing solutions market our primary competitors include GTUIT, LLC, Kinder Morgan Treating LP and Schlumberger Limited. In addition, our industry is highly fragmented and we compete regionally with a significant number of smaller service providers.

We believe that the principal competitive factors in the markets we serve are technical expertise, equipment capacity, work force competency, efficiency, safety record, reputation, experience and price. Additionally, projects are often awarded on a bid basis, which tends to create a highly competitive environment. We seek to differentiate ourselves from our competitors by delivering the highest-quality services and equipment possible, coupled with superior execution and operating efficiency in a safe working environment.

Cyclical Nature of Industry

We operate in a highly cyclical industry. The key factor driving demand for our services is the level of drilling activity by E&P companies, which in turn depends largely on the current and anticipated economics of new well completions. Global supply and demand for oil and the domestic supply and demand for natural gas are critical in assessing industry outlook. Demand for oil and natural gas is cyclical and subject to large, rapid fluctuations. E&P companies tend to increase capital expenditures in response to increases in oil and natural gas prices, which generally results in greater revenues and profits for oilfield service companies such as ours. Increased capital expenditures also ultimately lead to greater production, which historically has resulted in increased inventories and reduced prices which in

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turn tend to reduce demand for oilfield services. For these reasons, the results of our operations may fluctuate from quarter to quarter and from year to year, and these fluctuations may distort comparisons of results across periods.

Seasonality

Our results of operations have historically reflected seasonal tendencies relating to holiday seasons, inclement weather and the conclusion of our customers' annual drilling and completion capital expenditure budgets. Our most notable declines occur in the first and fourth quarters of the calendar year for the reasons described above. Additionally, some of the areas in which we have operations, including the Denver-Julesburg Basin and the Bakken Shale, are adversely affected by seasonal weather conditions, primarily in the winter and spring. During periods of heavy snow, ice, wind or rain, we may be unable to move our equipment between locations, thereby reducing our ability to provide services and generate revenues, or we could suffer weather-related damage to our facilities and equipment resulting in delays in operations. The exploration activities of our customers may also be affected during such periods of adverse weather conditions.

Sales and Marketing

Our sales and marketing activities typically are performed through our local operations in each geographical region, and are supported by sales representatives at our corporate headquarters. Our senior management also takes an active role in supporting our local sales and marketing operations and personnel. We believe our local field sales personnel understand the region‑specific issues and customer operating procedures and therefore can more effectively target marketing activities. Our sales representatives work closely with our local managers and field sales personnel to target market opportunities.

Customers

We have strong relationships with a broad customer base, including Devon Energy Corporation, EOG Resources, Inc., Noble Energy, Inc., Oasis Petroleum Inc., PDC Energy Inc. and Statoil ASA. During 2017 we worked for 269 distinct customers. During 2017 and 2016, EOG Resources, Inc. and PDC Energy Inc. each accounted for more than 10% of our revenues. During 2015, EOG Resources, Inc. and Whiting Petroleum Corporation each accounted for more than 10% of our revenues. After giving effect to the ESCO Acquisition, Devon Energy Corporation would have accounted for more than 10% of our revenues during 2017, 2016 and 2015. Our top five customers represented approximately 47%, 55% and 82% of our consolidated revenues for 2017, 2016 and 2015, respectively. Within our Well Services segment, our top five customers represented approximately 50%, 62% and 77% of our revenues for 2017, 2016 and 2015, respectively. Within our Processing Solutions segment, our top five customers represented approximately 92%, 90% and 98% of our revenues for 2017, 2016 and 2015, respectively.

Suppliers

We have built strong relationships with the manufacturers of our high‑spec well service rigs, and we believe we will continue to have timely access to new, high‑spec rigs as we continue to grow. For example, in February 2017, we entered into the NOV Purchase Agreement to meet expected customer demand for our high‑spec well service rigs. Further, we have built strong relationships with the third‑party suppliers and other vendors that we use to assemble our MRUs and related modular processing equipment, and believe we will continue to have timely access to new MRUs and related equipment as we continue to grow.

In addition, our internal supply chain team manages sourcing and logistics to ensure flexibility and continuity of supply in a cost effective manner across our areas of operation. We have built long‑term relationships with multiple industry leading suppliers of materials and equipment. We purchase a wide variety of materials, parts and components that are manufactured and supplied for our operations. We are not dependent on any single source of supply for those parts, supplies or materials. To date, we have generally been able to obtain the equipment, parts and supplies necessary to support our operations on a timely basis.

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Environmental and Occupational Safety and Health Matters

Our operations, which support the oil and natural gas exploration, development and production activities pursued by our customers, are subject to stringent and comprehensive federal, regional, state and local laws and regulations governing occupational safety and health, the discharge of materials into the environment, solid and hazardous waste management, transportation and disposal, and environmental protection. These laws and regulations may, among other things (i) limit or prohibit our operations on certain lands lying within wilderness, wetlands and other protected areas; (ii) require remedial measures to mitigate or clean-up pollution from former and ongoing operations; (iii) impose restrictions on the types, quantities and concentrations of various substances that can be released into the environment or injected in formations in connection with oil and natural gas drilling and production activities; (iv) impose specific safety and health standards or criteria addressing worker protection; and (v) impose substantial liabilities for pollution resulting from our operations.

Numerous governmental entities, including the U.S. Environmental Protection Agency (“EPA”) and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them. Any failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil and criminal penalties, the imposition of investigatory, remedial or corrective action obligations or the incurrence of capital expenditures; the occurrence of delays in the permitting or performance of projects; the issuance of orders enjoining performance of some or all of our operations in a particular area; and governmental or private claims for personal injury or property or natural resource damages.

The trend in environmental regulation has been to place more restrictions and limitations on activities that may adversely affect the environment, and thus any changes in environmental laws and regulations or re-interpretation of enforcement policies that result in more stringent and costly regulatory requirements could have a material adverse effect on our business, liquidity position, financial condition, prospects and results of operations. We may be unable to pass on such increased compliance costs to our customers. Moreover, accidental releases or spills may occur in the course of our operations, and we cannot assure you that we will not incur significant costs and liabilities as a result of such releases or spills, including any third-party claims for damage to property, natural resources or persons. Our customers may also incur increased costs or delays or restrictions in permitting or operating activities as a result of more stringent environmental laws and regulations, which may result in a curtailment of exploration, development or production activities that would reduce the demand for our services.

The following is a summary of the more significant existing environmental and occupational safety and health laws, as amended from time to time, to which our business is subject and for which compliance may have a material adverse impact on our capital expenditures, results of operations or financial position.

Worker Health and Safety

We are subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”), and comparable state statutes that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard requires that information be maintained about hazardous materials used or produced in operations and that this information be provided to employees, state and local government authorities and the public.

Radioactive Materials

Some of our operations utilize equipment that contains sealed, low-grade radioactive sources. Our activities involving the use of radioactive materials are regulated by the United States Nuclear Regulatory Commission (“NRC”) and state regulatory agencies under agreement with the NRC. Standards implemented by these regulatory agencies require us to obtain licenses or other approvals for the use of such radioactive materials. Historically, our radioactive materials compliance costs have not had a material adverse effect on our business, liquidity position, financial condition, prospects or results of operations; however, there can be no assurance that such costs will not be material in the future. The violation of these laws and regulations may result in the denial or revocation of permits, issuance of corrective action orders, injunctions prohibiting some or all of our operations in a particular area, and assessment of sanctions, including administrative, civil and criminal penalties. In addition, a release of radioactive material could result in substantial remediation costs, and potentially expose us to third party property damage or personal injury claims.

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Naturally Occurring Radioactive Materials (“NORM”) may contaminate extraction and processing equipment used in the oil and natural gas industry, most often in the form of scale. The waste resulting from such contamination is regulated by federal and state laws. Standards have been developed for: worker protection; treatment, storage, and disposal of NORM and NORM waste; management of NORM-contaminated waste piles, containers and tanks; and limitations on the relinquishment of NORM contaminated land for unrestricted use under RCRA and state laws. We may incur significant costs or liabilities associated with elevated levels of NORM.

Hazardous Substances and Wastes and Naturally Occurring Radioactive Materials

The Resource Conservation and Recovery Act (“RCRA”), and comparable state statutes, regulate the generation, treatment, storage, transportation, disposal and clean-up of hazardous and non-hazardous wastes. Pursuant to rules issued by the EPA, individual states can have delegated authority to administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. In the course of our operations, we generate industrial wastes, such as paint wastes, waste solvents and waste oils that are regulated as hazardous wastes. Drilling fluids, produced waters, and most of the other wastes associated with the exploration, development, and production of oil or natural gas, if properly handled, are currently exempt from regulation as hazardous waste under RCRA and, instead, are regulated under RCRA’s less stringent non-hazardous waste provisions, or other state or federal laws.

However, it is possible that certain oil and natural gas drilling and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future. For example, the EPA is required by a consent decree to propose a rulemaking for revision of certain RCRA Subtitle D criteria regulations pertaining to oil and natural gas wastes or sign a determination that revision of the regulations is not necessary no later than March 15, 2019. If EPA proposes a rulemaking for revised oil and natural gas waste regulations, the consent decree requires that the EPA take final action following notice and comment rulemaking no later than July 15, 2021. A reclassification of drilling fluids, produced waters and related wastes as hazardous under RCRA could result in an increase in our, as well as the oil and natural gas exploration and production industries’, costs to manage and dispose of generated wastes, which could have a material adverse effect on our business, liquidity position, financial condition, prospects and results of operations. Additionally, other wastes handled at exploration and production sites or generated in the course of providing well services may not fall within this exclusion.

The Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), and comparable state laws impose strict, joint and several liability for environmental contamination and damages to natural resources without regard to fault or the legality of the original conduct on certain classes of persons. These persons include owners and operators of real property impacted by a release of hazardous substances and any company that transported, disposed of, or arranged for the transport or disposal of hazardous substances to or at the site. Under CERCLA, such persons may be liable for, among other things, the costs of remediating the hazardous substances that have been released into the environment, for damages to natural resources, and for the costs of certain health studies. In addition, where contamination may be present, it is not uncommon for the neighboring landowners and other third parties to file claims for personal injury, property damage and recovery of response costs.

Water Discharges and Discharges into Belowground Formations

The Federal Water Pollution Control Act, also known as the Clean Water Act (“CWA”), and analogous state laws, impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and hazardous substances, into state waters and waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. Spill prevention, control and countermeasure plan requirements imposed under the CWA require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. In addition, the CWA and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. The CWA also prohibits the discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by permit. The CWA and analogous state laws also may impose substantial civil and criminal penalties for non-compliance including spills and other non-authorized discharges.

The Oil Pollution Act of 1990 (“OPA”) sets minimum standards for prevention, containment and cleanup of oil spills. The OPA applies to vessels, offshore facilities, and onshore facilities, including exploration and production

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facilities that may affect waters of the United States. Under the OPA, responsible parties including owners and operators of onshore facilities may be held strictly liable for oil cleanup costs and natural resource damages as well as a variety of public and private damages that may result from oil spills. The OPA also requires owners or operators of certain onshore facilities to prepare Facility Response Plans for responding to a worst-case discharge of oil into waters of the United States.

Our oil and natural gas producing customers dispose of flowback and produced water or certain other oilfield fluids gathered from oil and natural gas producing operations in accordance with permits issued by government authorities overseeing such disposal activities. While these permits are issued pursuant to existing laws and regulations, these legal requirements are subject to change based on concerns of the public or governmental authorities regarding such disposal activities. One such concern relates to recent seismic events near underground disposal wells used for the disposal by injection of flowback and produced water or certain other oilfield fluids resulting from oil and natural gas activities. When caused by human activity, such events are called induced seismicity. In response to concerns regarding induced seismicity, regulators in some states have imposed, or are considering imposing, additional requirements in the permitting of produced water disposal wells or otherwise to assess any relationship between seismicity and the use of such wells. States may, from time to time, develop and implement plans directing certain wells where seismic incidents have occurred to restrict or suspend disposal well operations. In addition, ongoing lawsuits allege that disposal well operations have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. These developments could result in additional regulation and restrictions on the use of injection wells by our customers to dispose of flowback and produced water and certain other oilfield fluids. Increased regulation and attention given to induced seismicity also could lead to greater opposition to, and litigation concerning, oil and natural gas activities utilizing injection wells for waste disposal.

Any one or more of these developments may result in our customers having to limit disposal well volumes, disposal rates or locations, or require our customers or third party disposal well operators that are used to dispose of customer wastewater to shut down disposal wells, which developments could adversely affect our customers’ business and result in a corresponding decrease in the need for our services, which would could have a material adverse on our business, liquidity position, financial condition, prospects and results of operations.

Air Emissions

Some of our operations also result in emissions of regulated air pollutants. The federal Clean Air Act (“CAA”) and analogous state laws require permits for certain facilities that have the potential to emit substances into the atmosphere that could adversely affect environmental quality. These laws and their implementing regulations also impose limitations on air emissions and require adherence to maintenance, work practice, reporting and record keeping, and other requirements. Failure to obtain a permit or to comply with permit or other regulatory requirements could result in the imposition of sanctions, including administrative, civil and criminal penalties. In addition, we or our customers could be required to shut down or retrofit existing equipment, leading to additional capital or operating expenses and operational delays.

Many of these regulatory requirements, including New Source Performance Standards (“NSPS”) and Maximum Achievable Control Technology standards, are expected to be made more stringent over time as a result of stricter ambient air quality standards and other air quality protection goals adopted by the EPA. Compliance with these or other new regulations could, among other things, require installation of new emission controls on some of our equipment, result in longer permitting timelines, and significantly increase our capital expenditures and operating costs, which could adversely impact on our business. For example, the EPA issued final CAA regulations in 2012 that include NSPS standards for VOC emissions from completions of hydraulically fractured natural gas wells, compressors, controllers, dehydrators, storage tanks, natural gas processing plants and certain other equipment. In June 2016, the EPA published additional final rules establishing new emissions standards for methane and additional standards for VOCs from certain new, modified and reconstructed equipment and processes in the oil and natural gas source category, including production, processing, transmission and storage activities, and is formally seeking additional information from oil and natural gas producing companies as necessary to eventually expand these final rules to include existing equipment and processes. However, in June 2017, the EPA published a proposal to stay certain portions of the June 2016 standards for two years and re-evaluate the entirety of the 2016 standards but the EPA has not yet adopted the proposal and, as a result, the June 2016 rule remains in effect but future implementation of the 2016 standards is uncertain at this time. In addition, some of our customers operate on federal or tribal lands, and are thus subject to additional requirements, including those impose by tribal authorities and the federal Bureau of Land Management (“BLM”). For example, in June

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2016, the EPA issued a Federal Implementation Plan (“FIP”) to implement the Federal Minor New Source Review Program on tribal lands for oil and gas production. The FIP creates a permit-by-rule process for minor sources that also incorporates emission limits and other requirements under various federal air quality standards, applying them to a range of equipment and processes used in oil and gas production. The FIP does not apply in areas of ozone non-attainment. As a result, the EPA may impose area-specific regulations in certain areas identified as tribal lands that may require additional emissions controls on existing equipment. Such requirements will likely result in increased operating and compliance costs for our customers in these regions.

In November 2016, the BLM finalized a rule regulating the venting and flaring of natural gas, leak detection, air emissions from equipment, well maintenance and unloading, drilling and completions and royalties potentially owed for loss of such emissions from oil and natural gas facilities producing on federal and tribal leases. The final rule became effective in January 2017; however, BLM issued a final rule in December 2017 delaying implementation of the venting and flaring rule for one year. The venting and flaring rule is also the subject of pending litigation filed by oil and natural gas trade associations and certain states seeking to modify or overturn the rule. In addition, in a March 28, 2017 executive order, President Trump directed the Secretary of the Interior to review these and several other BLM rules related to oil and gas operations and, if appropriate, to suspend, revise, or rescind the rules. The executive order also directs all executive agencies more broadly to review existing regulations that potentially burden the development or use of domestically produced energy resources. Compliance with these and other air pollution control and permitting requirements has the potential to delay the development of oil and natural gas projects and increase costs for us and our customers. Moreover, our business could be materially affected if these or other similar requirements increase the cost of doing business for us and our customers, or reduce the demand for the oil and natural gas our customers produce, and thus have an adverse effect on the demand for our services.

Climate Change

In the United States, domestic efforts to curb Green House Gas (“GHG”) emissions continue to be led by the EPA’s GHG regulations as well as state and regional efforts aimed at tracking and/or reducing GHG emissions by means of cap and trade programs. In addition, the EPA has determined that GHG emissions present a danger to public health and the environment and has adopted regulations that, among other things, restrict emissions of GHGs under existing provisions of the CAA and may require the installation of “best available control technology” to limit emissions of GHGs from any new or significantly modified facilities if they would otherwise emit large volumes of GHGs together with other criteria pollutants. Also, the EPA has adopted rules requiring the monitoring and Annual Reporting of GHG emissions from oil and natural gas production, processing, transmission and storage facilities in the United States on an annual basis, including gathering and boosting stations as well as completions and workovers from hydraulically fractured oil wells. The EPA has also taken steps to limit methane emissions, a GHG, from certain new modified or reconstructed facilities in the oil and natural gas sector, but future implementation of these methane rules is uncertain at this time.

In December 2015, the United States joined an agreement at the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France that requires member countries to review and “represent a progression” in their intended nationally determined contributions, which set GHG emission reduction goals, every five years beginning in 2020 (the “Paris Agreement”). The Paris Agreement entered into force in November 2016. Although this agreement does not create any binding obligations for nations to limit their GHG emissions, it does include pledges to voluntarily limit or reduce future emissions. In June 2017, President Trump stated that the United States would withdraw from the Paris Agreement, but may enter into a future international agreement related to GHGs. Substantial limitations on GHG emissions could adversely affect demand for the oil and natural gas our customers produce and lower the value of their reserves, which developments could reduce demand for our services and have a corresponding material adverse effect on our business, liquidity position, financial condition, prospects and results of operations. Finally, increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events. If any such effects were to occur, they could have an adverse effect on our operations.

Hydraulic Fracturing

Our customers are reliant on hydraulic fracturing services in connection with their production of oil and natural gas. Hydraulic fracturing stimulates production of oil and/or natural gas from dense subsurface rock formations by

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injecting water, sand and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production.

Hydraulic fracturing typically is regulated by state oil and natural gas commissions, but the EPA has asserted federal regulatory authority pursuant to the Safe Drinking Water Act over certain hydraulic fracturing activities involving the use of diesel fuel and issued permitting guidance in February 2014 that applies to such activities. The EPA also finalized rules in June 2016 that prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants. In addition, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources in December 2016. The final report concluded that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources “under some circumstances,” noting that the following hydraulic fracturing water cycle activities and local- or regional-scale factors are more likely than others to result in more frequent or more severe impacts: water withdrawals for fracturing in times or areas of low water availability; surface spills during the management of fracturing fluids, chemicals or produced water; injection of fracturing fluids into wells with inadequate mechanical integrity; injection of fracturing fluids directly into groundwater resources; discharge of inadequately treated fracturing wastewater to surface waters; and disposal or storage of fracturing wastewater in unlined pits.

Additionally, the BLM finalized a rule in March 2015 establishing standards for hydraulic fracturing on federal and American Indian lands, but subsequently repealed the rule in December 2017. BLM’s repeal of the rule has been challenged in federal court. In addition, various state and local governments have implemented, or are considering, increased regulatory oversight of hydraulic fracturing through additional permit requirements, operational restrictions, disclosure requirements, well construction and temporary or permanent bans on hydraulic fracturing in certain areas. For example, Texas, Colorado and North Dakota, among others, have adopted regulations that impose new or more stringent permitting, disclosure, disposal, and well construction requirements on hydraulic fracturing operations.

In addition to state laws, local land use restrictions, such as city ordinances, may restrict drilling in general and/or hydraulic fracturing in particular. If new federal, state or local laws or regulations that significantly restrict hydraulic fracturing are adopted, such legal requirements could result in delays, eliminate certain drilling and injection activities and make it more difficult or costly to perform hydraulic fracturing. Any such regulations limiting or prohibiting hydraulic fracturing could result in decreased oil and natural gas exploration and production activities and, therefore, adversely affect demand for our services and our business. Such laws or regulations could also materially increase our costs of compliance and doing business.

Historically, our environmental compliance costs have not had a material adverse on our business, liquidity position, financial condition, prospects and results of operations; however, there can be no assurance that such costs will not be material in the future. It is possible that substantial costs for compliance or penalties for non-compliance may be incurred in the future. Moreover, it is possible that other developments, such as the adoption of stricter environmental laws, regulations, and enforcement policies, could result in additional costs or liabilities that we cannot currently quantify.

State and Local Regulation

Our operations, and the operations of our customers, are subject to a variety of state and local environmental review and permitting requirements. Some states have state laws similar to major federal environmental laws and thus our operations are also subject to state requirements that may be more stringent than those imposed under federal law.

Our operations may require state-law based permits in addition to federal permits, requiring state agencies to consider a range of issues, many the same as federal agencies, including, among other things, a project’s impact on wildlife and their habitats, historic and archaeological sites, aesthetics, agricultural operations, and scenic areas. Texas has specific permitting and review processes for oilfield service operations, and state agencies may impose different or additional monitoring or mitigation requirements than federal agencies. The development of new sites and our existing operations also are subject to a variety of local environmental and regulatory requirements, including land use, zoning, building, and transportation requirements.

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Motor Carrier Operations

We operate as a motor carrier and therefore are subject to regulation by the U.S. Department of Transportation (“DOT”) and various state agencies. These regulatory authorities exercise broad powers, governing activities such as the authorization to engage in motor carrier operations; regulatory safety; hazardous materials labeling, placarding and marking; financial reporting; and certain mergers, consolidations and acquisitions. There are additional regulations specifically relating to the trucking industry, including testing and weight and dimension specifications of equipment, drug testing of drivers and product handling requirements. The trucking industry is subject to possible regulatory and legislative changes that may affect the economics of the industry by requiring changes in operating practices or by changing the demand for common or contract carrier services or the cost of providing truckload services. Some of these possible changes include increasingly stringent environmental regulations, changes in the hours of service regulations which govern the amount of time a driver may drive in any specific period and requiring onboard black box recorder devices or limits on vehicle weight and size.

Interstate motor carrier operations are subject to safety requirements prescribed by DOT. Intrastate motor carrier operations are subject to safety regulations that often mirror federal regulations. Such matters as weight and dimension of equipment are also subject to federal and state regulations. DOT regulations also mandate drug testing of drivers. From time to time, various legislative proposals are introduced, including proposals to increase federal, state or local taxes, including taxes on motor fuels, which may increase our costs or adversely impact the recruitment of drivers. We cannot predict whether, or in what form, any increase in such taxes applicable to us will be enacted.

Employees

As of December 31, 2017, we had approximately 1,049 employees and no unionized labor. We hire independent contractors on an as-needed basis. We believe we have satisfactory relations with our employees.

Available Information

We file or furnish annual, quarterly and current reports, proxy statements and other documents with the SEC under the Exchange Act. The public may read and copy any materials we file with the SEC at the SEC’s Public Reference Room at 100 F Street, NE, Washington, D.C. 20549, on official business days during the hours of 10 a.m. to 3 p.m. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC also maintains an internet website at www.sec.gov that contains reports, proxy and information statements and other information regarding issuers, including us, that file electronically with the SEC.

Our Class A Common Stock is listed and traded on the New York Stock Exchange ("NYSE") under the symbol "RNGR." Our reports, proxy statements and other information filed with the SEC can also be inspected and copied at the offices of the NYSE, at 20 Broad Street, New York, New York 10005.

We also make available free of charge through our website, www.rangerenergy.com, electronic copies of certain documents that we file with the SEC, including our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC.

 

Item 1A. Risk Factors

Investing in our Class A Common Stock involves risks. You should carefully consider the information in this Annual Report, including the matters addressed under “Cautionary Note Regarding Forward‑Looking Statements” and the following risks before making an investment decision. If any of the following risks actually occur, the trading price of our Class A Common Stock could decline, and you may lose all or part of your investment. Additional risks not presently known to us or that we currently deem immaterial could also materially affect our business.

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Risks Related to Our Business

Our business depends on domestic capital spending by the oil and natural gas industry, and reductions in such capital spending could have a material adverse effect on our business, liquidity position, financial condition, prospects and results of operations.

Our business is directly affected by our customers’ capital spending to explore for, develop and produce oil and natural gas in the United States. The significant decline in oil and natural gas prices that began in late 2014 has caused a reduction in the exploration, development and production activities of most of our customers and their spending on our services. These cuts in spending have curtailed drilling programs, which has resulted in a reduction in the demand for our services as compared to activity levels in late 2014, as well as in the prices we can charge. In addition, certain of our customers could become unable to pay their vendors and service providers, including us, as a result of the decline in commodity prices. Reduced discovery rates of new oil and natural gas reserves in our areas of operation as a result of decreased capital spending may also have a negative long‑term impact on our business, even in an environment of stronger oil and natural gas prices, to the extent the reduced number of wells that need our services or equipment more than offsets new drilling and completion activity and complexity. Any of these conditions or events could adversely affect our operating results. If the recent recovery does not continue or our customers fail to further increase their capital spending, it could have a material adverse effect on our business, liquidity position, financial condition, prospects and results of operations.

Industry conditions are influenced by numerous factors over which we have no control, including:

domestic and foreign economic conditions and supply of and demand for oil and natural gas;

the level of prices, and expectations about future prices, of oil and natural gas;

the level and cost of global and domestic oil and natural gas exploration, production, transportation of reserves and delivery;

taxes and governmental regulations, including the policies of governments regarding the exploration for and production and development of their oil and natural gas reserves;

political and economic conditions in oil and natural gas producing countries;

actions by the members of the Organization of Petroleum Exporting Countries (“OPEC”) with respect to oil production levels and announcements of potential changes in such levels, including the failure of such countries to comply with production cuts announced in November 2016;

global weather conditions and natural disasters;

worldwide political, military and economic conditions;

the discovery rates of new oil and natural gas reserves;

shareholder activism or activities by non‑governmental organizations to restrict the exploration, development and production of oil and natural gas;

advances in exploration, development and production technologies or in technologies affecting energy consumption;

the potential acceleration of development of alternative fuels; and

uncertainty in capital and commodities markets and the ability of oil and natural gas companies to raise equity capital and debt financing.

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The volatility of oil and natural gas prices may adversely affect the demand for our services and negatively impact our results of operations.

The demand for our services is primarily determined by current and anticipated oil and natural gas prices and the related levels of capital spending and drilling activity in the areas in which we have operations. Volatility or weakness in oil prices or natural gas prices (or the perception that oil prices or natural gas prices will decrease) affects the spending patterns of our customers and may result in the drilling of fewer new wells. This, in turn, could lead to lower demand for our services and may cause lower utilization of our assets. We have, and may in the future, experience significant fluctuations in operating results as a result of the reactions of our customers to changes in oil and natural gas prices. For example, prolonged low commodity prices experienced by the oil and natural gas industry beginning in late 2014 and uncertainty about future prices even when prices increased, combined with adverse changes in the capital and credit markets, caused many E&P companies to significantly reduce their capital budgets and drilling activity. This resulted in a significant decline in demand for oilfield services and adversely impacted the prices oilfield services companies could charge for their services.

Prices for oil and natural gas historically have been extremely volatile and are expected to continue to be volatile. During the past three years, the posted WTI price for oil has ranged from a low of $26.21 per Bbl in February 2016 to a high of $107.26 per Bbl in June 2014. During 2017, WTI prices ranged from $46.32 to $65.64 per Bbl. If the prices of oil and natural gas continue to be volatile, reverse their recent increases or decline, our operations, financial condition, cash flows and level of expenditures may be materially and adversely affected.

We may be adversely affected by uncertainty in the global financial markets and the deterioration of the financial condition of our customers.

Our future results may be impacted by the uncertainty caused by an economic downturn, volatility or deterioration in the debt and equity capital markets, inflation, deflation or other adverse economic conditions that may negatively affect us or parties with whom we do business resulting in a reduction in our customers’ spending and their non‑payment or inability to perform obligations owed to us, such as the failure of customers to honor their commitments or the failure of major suppliers to complete orders. Additionally, during times when the natural gas or crude oil markets weaken, our customers are more likely to experience financial difficulties, including being unable to access debt or equity financing, which could result in a reduction in our customers’ spending for our services. In addition, in the course of our business we hold accounts receivable from our customers. In the event of the financial distress or bankruptcy of a customer, we could lose all or a portion of such outstanding accounts receivable associated with that customer. Further, if a customer was to enter into bankruptcy, it could also result in the cancellation of all or a portion of our service contracts with such customer at significant expense or loss of expected revenues to us.

Our operations are subject to inherent risks, some of which are beyond our control. These risks may be self‑insured, or may not be fully covered under our insurance policies.

Our operations are subject to hazards inherent in the oil and natural gas industry, such as, but not limited to, accidents, blowouts, explosions, craterings, fires, oil spills and releases of drilling, completion or fracturing fluids or hazardous materials into the environment. These conditions can cause:

disruption or suspension of operations;

substantial repair or replacement costs;

personal injury or loss of human life;

significant damage to or destruction of property and equipment;

environmental pollution, including groundwater contamination;

unusual or unexpected geological formations or pressures and industrial accidents; and

substantial revenue loss.

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In addition, our operations are subject to, and exposed to, employee/employer liabilities and risks such as wrongful termination, discrimination, labor organizing, retaliation claims and general human resource‑related matters.

The occurrence of a significant event or adverse claim in excess of the insurance coverage that we maintain or that is not covered by insurance could have a material adverse effect on our business, liquidity position, financial condition, prospects and results of operations and may increase our costs. Claims for loss of oil and natural gas production and damage to formations can occur in the well services industry. Litigation arising from a catastrophic occurrence at a location where our equipment and services are being used may result in our being named as a defendant in lawsuits asserting large claims.

We do not have insurance against all risks, either because insurance is not available or because of the high premium costs. The occurrence of an event not fully insured against or the failure of an insurer to meet its insurance obligations could result in substantial losses. In addition, we may not be able to maintain adequate insurance in the future at rates we consider reasonable. Insurance may not be available to cover any or all of the risks to which we are subject, or, even if available, it may be inadequate, or insurance premiums or other costs could rise significantly in the future so as to make such insurance prohibitively expensive.

Reliance upon a few large customers may adversely affect our revenues and operating results.

Our top five customers represented approximately 47%, 55% and 82% of our consolidated revenues for 2017, 2016 and 2015, respectively. Within our Well Services segment, our top five customers represented approximately 50%, 62% and 77% of our Well Services segment revenues for 2017, 2016 and 2015, respectively. Within our Processing Solutions segment, our top five customers represented approximately 92%, 90% and 98% of our Processing Solutions segment revenues for 2017, 2016 and 2015, respectively. It is likely that we will continue to derive a significant portion of our revenue from a relatively small number of customers in the future. If a major customer fails to pay us, our revenues would be impacted and our operating results and financial condition could be materially harmed. Additionally, if we were to lose any material customer, we may not be able to redeploy our equipment at similar utilization or pricing levels or within a short period of time and such loss could have a material adverse effect on our business, liquidity position, financial condition, prospects and results of operations until the equipment is redeployed at similar utilization or pricing levels.

We are exposed to the credit risk of our customers, and any material nonpayment or nonperformance by our customers could adversely affect our financial results.

We are subject to the risk of loss resulting from nonpayment or nonperformance by our customers, many of whose operations are concentrated solely in the domestic E&P industry which, as described above, is subject to volatility and, therefore, credit risk. Our credit procedures and policies may not be adequate to fully reduce customer credit risk. If we are unable to adequately assess the creditworthiness of existing or future customers or unanticipated deterioration in their creditworthiness, any resulting increase in nonpayment or nonperformance by them and our inability to re‑market or otherwise use our equipment could have a material adverse effect on our business, liquidity position, financial condition, prospects or results of operations.

We face intense competition that may cause us to lose market share and could negatively affect our ability to market our services and expand our operations.

The oilfield services business is highly competitive and fragmented. Some of our competitors are small companies capable of competing effectively in our markets on a local basis, while others have a broader geographic scope, greater financial and other resources, or other cost efficiencies. Our competitors may be able to respond more quickly to new or emerging technologies and services and changes in customer requirements. Additionally, there may be new companies that enter our business, or re‑enter our business with significantly reduced indebtedness following emergence from bankruptcy, or our existing and potential customers may develop their own oilfield services business. Our ability to maintain current revenues and cash flows, and our ability to market our services and expand our operations, could be adversely affected by the activities of our competitors and our customers. If our competitors substantially increase the resources they devote to the development and marketing of competitive services or substantially decrease the prices at which they offer their services, we may be unable to effectively compete. Many contracts are awarded on a bid basis, which may further increase competition based primarily on price. The competitive environment may be further intensified by mergers and acquisitions among oil and natural gas companies or other events

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that have the effect of reducing the number of available customers. All of these competitive pressures could have a material adverse effect on our business, liquidity position, financial condition, prospects and results of operations. Some of our larger competitors provide a broader range of services on a regional, national or worldwide basis. These companies may have a greater ability to continue oilfield service activities during periods of low commodity prices and to absorb the burden of present and future federal, state, local and other laws and regulations. Any inability to compete effectively could have a material adverse impact on our financial condition and results of operations.

We currently rely on a limited number of third‑party manufacturers to build the new high‑spec well service rigs that we purchase, and such reliance exposes us to risks including price and timing of delivery.

We currently rely on a limited number of third‑party manufacturers to build our new high‑spec well service rigs. For example, approximately 62% of our high‑spec well service rigs were manufactured by NOV. Pursuant to the NOV Purchase Agreement, we accepted delivery of an additional 16 high‑spec well service rigs in 2017 and expect to accept delivery of 9 more high-spec rigs during 2018; however, NOV is not obligated pursuant to the NOV Purchase Agreement to deliver such high‑spec well service rigs during 2017, and will not face penalties for delayed delivery, regardless of the length or cause of any delay. If demand for high‑spec well service rigs or the components necessary to build such high‑spec well service rigs increases or our manufacturers’ suppliers face financial distress or bankruptcy, such manufacturers, including NOV, may not be able to provide the new high‑spec well service rigs to us on schedule or at expected prices. If this were to occur, we could be required to seek other manufacturers to build our high‑spec well service rigs and, other than the manufacturers on which we currently rely, there are a limited number of additional manufacturers that are capable of building high‑spec service rigs to our specifications. Disruptions in the ability of our manufacturers to deliver our new high‑spec well service rigs may adversely affect our revenues or increase our costs.

Our operating history may not be sufficient for investors to evaluate our business and prospects.

We are a recently consolidated company with a short consolidated operating history, which makes it difficult for potential investors to evaluate our prospective business or operations or the merits of an investment in our securities. The Magna, Bayou and ESCO Acquisitions were completed in June 2016, October 2016 and August 2017, respectively, and our Predecessor’s consolidated financial and operating results only reflect the impact of such acquisitions for periods subsequent to such acquisitions. In addition, the Predecessor Companies, became our operating subsidiaries and have not historically operated on a consolidated or combined basis or under the same management team. Further, certain members of our and ESCO’s management teams have a limited history operating together and may experience difficulties relating to the efficient integration of varying management systems, processes and procedures. These factors may make it more difficult for investors to evaluate our business and prospects and to forecast our future operating results. For example, the historical financial data may not give you an accurate indication of what our actual results would have been if our corporate reorganization, the Magna, Bayou and ESCO Acquisitions, or the formation of our management team had been completed at the beginning of the periods presented or of what our future results of operations are likely to be. Our future results will depend on our ability to efficiently manage our combined operations and execute our business strategy.

Further, due to the sharp decline in demand for well services beginning in late 2014, and the recent recovery of activity in the well services industry, comparisons of our current and future operating results with prior periods may have limited utility.

The growth of our business through potential future acquisitions may expose us to various risks, including those relating to difficulties in identifying suitable, accretive acquisition opportunities and integrating businesses, assets and personnel, as well as difficulties in obtaining financing for targeted acquisitions and the potential for increased leverage or debt service requirements.

We have pursued and intend to continue to pursue selected, accretive acquisitions of complementary assets and businesses. Acquisitions involve numerous risks, including:

unanticipated costs and exposure to liabilities assumed in connection with the acquired business or assets, including but not limited to environmental liabilities;

difficulties in integrating the operations and assets of the acquired business and the acquired personnel;

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limitations on our ability to properly assess and maintain an effective internal control environment over an acquired business;

potential losses of key employees and customers of the acquired business;

risks of entering markets in which we have limited prior experience; and

increases in our expenses and working capital requirements.

The process of integrating an acquired business, including in connection with our corporate reorganization, may involve unforeseen costs and delays or other operational, technical and financial difficulties and may require a significant amount of time and resources. Our failure to incorporate the acquired business and assets into our existing operations successfully or to minimize any unforeseen operational difficulties could have a material adverse effect on our business, liquidity position, financial condition, prospects and results of operations. Furthermore, there is intense competition for acquisition opportunities in our industry. Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions.

In addition, we may not have sufficient capital resources to complete any additional acquisitions. Historically, we have financed our acquisitions primarily with funding from our equity investors, commercial borrowings and cash generated by operations. We may incur substantial indebtedness to finance future acquisitions and also may issue equity, debt or convertible securities in connection with such acquisitions. Debt service requirements could represent a significant burden on our results of operations and financial condition, and the issuance of additional equity or convertible securities could be dilutive to our existing shareholders. Furthermore, we may not be able to obtain additional financing as needed or on satisfactory terms.

Our ability to continue to grow through acquisitions and manage growth will require us to continue to invest in operational, financial and management information systems and to attract, retain, motivate and effectively manage our employees. The inability to effectively manage the integration of acquisitions, including in connection with our corporate reorganization, could reduce our focus on current operations, which, in turn, could negatively impact our earnings and growth. Our financial position and results of operations may fluctuate significantly from period to period, based on whether or not significant acquisitions are completed in particular periods.

We may be unable to successfully integrate acquired assets to realize anticipated benefits of any acquisition.

Our ability to achieve the anticipated benefits of any acquisition, such as the ESCO Acquisition, will depend in part upon whether we can integrate the acquired assets into our existing business in an efficient and effective manner. We may not be able to accomplish this integration process successfully. The successful acquisition of high‑spec well service rigs requires an assessment of several factors, including future oil and natural gas prices, the corresponding demand for high‑spec well service rigs (including on a basin‑by‑basin basis) and associated services and expected future rig utilization.

The accuracy of these assessments is inherently uncertain. The integration process may be subject to delays or changed circumstances, and we can give no assurance that the acquired assets will perform in accordance with our expectations or that our expectations with respect to integration or benefits as a result of any acquisition will materialize. Further, any acquisition may involve other risks that may cause our business to suffer, including:

diversion of our management’s attention to evaluating, negotiating for and integrating acquired assets;

the challenge and cost of integrating acquired assets with those of ours while carrying on our ongoing business; and

the failure to realize the full benefits anticipated from the acquisition or to realize these benefits within our expected time frame.

Because the historical rig utilization of any acquired assets may be lower than ours in recent periods, our rig utilization could decrease during the course of an initial integration period. Accordingly, there can be no assurance that

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the rig utilization for the well service rigs acquired in any acquisition will align with the rig utilization of the well service rigs in our existing well service rig fleet on our anticipated timeline or at all.

We may have difficulty managing growth in our business, which could adversely affect our financial condition and results of operations.

As a recently formed company, growth in accordance with our business plan, if achieved, could place a significant strain on our financial, operational and management resources. As we expand the scope of our activities and our geographic coverage through both organic growth and acquisitions, there will be additional demands on our financial, technical, operational and management resources. The failure to continue to upgrade our technical, administrative, operating and financial control systems or the occurrences of unexpected expansion difficulties, including the failure to recruit and retain experienced managers, engineers and other professionals in the oilfield services industry, could have a material adverse effect on our business, liquidity position, financial condition, prospects and results of operations and our ability to successfully or timely execute our business plan.

We will incur significant capital expenditures for new equipment as we grow our operations and may be required to incur further capital expenditures as a result of advancements in oilfield services technologies.

As we grow our operations we will be required to incur significant capital expenditures to build, acquire, update or replace our existing well service rigs and other equipment. Such demands on our capital and the increase in cost of labor necessary to operate such well service rigs and other equipment could have a material adverse effect on our business, liquidity position, financial condition, prospects and results of operations and may increase our costs. To the extent we are unable to fund such projects, we may have less equipment available for service or our equipment may not be attractive to current or potential customers.

In addition, because the oilfield services industry is characterized by significant technological advancements and introductions of new products and services using new technologies, we may lose market share or be placed at a competitive disadvantage as competitors and others use or develop new technologies or technologies comparable to ours in the future. Further, we may face competitive pressure to implement or acquire certain new technologies at a substantial cost. Some of our competitors may have greater financial, technical and personnel resources than we do, which may allow them to gain technological advantages or implement new technologies before we can. Additionally, we may be unable to implement new technologies or services at all, on a timely basis or at an acceptable cost.

In addition to technological advancements by our competitors, new technology could also make it easier for our customers to vertically integrate their operations or otherwise conduct their activities without the need for our equipment and services, thereby reducing or eliminating the need for our services. For example, if further advancements in drilling and completion techniques cause our E&P customers to require well service rigs with different or higher specifications than those in our existing and expected future fleet, or to otherwise require well service equipment that we do not currently own or operate, we may be required to incur significant additional capital expenditures to obtain any such new rigs or other equipment in an effort to meet customer demand. Limits on our ability to effectively obtain, use, implement or integrate new technologies may have a material adverse effect on our business, liquidity position, financial condition, prospects and results of operations.

Increases in the scope or pace of midstream infrastructure development, or decreased federal or state regulation of natural gas pipelines, could decrease demand for our services.

Increases in the scope or pace of midstream infrastructure development could decrease demand for our services. Our processing solutions are designed 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. Specifically, our modular MRUs are used by our customers to meet pipeline specifications, extract higher value NGLs, provide fuel gas for well sites and facilities and reduce emissions at the flare tip, services that are generally required when E&P companies drill oil and natural gas wells in basins without immediate access to sufficient midstream infrastructure and takeaway capacity. To the extent that permanent midstream infrastructure is developed in the basins in which we operate, or the pace of existing development is accelerated as a result of customer demand, the demand for our processing solutions could decrease.

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In addition, there has recently been increasing public controversy regarding construction of new natural gas pipelines and the stringency of current regulation of natural gas pipelines, creating uncertainty as to the probability and timing of such construction. Decreases to the stringency of regulation of existing natural gas pipelines at either the state or federal level could reduce the demand for our services and could have a material adverse effect on our business, liquidity position, financial condition, prospects and results of operations.

We may be unable to employ or retain a sufficient number of skilled and experienced workers.

We are dependent upon the available labor pool of skilled employees and may not be able to find or retain enough skilled labor to meet our needs, which could have a negative effect on our growth. The delivery of our products and services requires workers with specialized skills and experience who can perform physically demanding work. As a result of our industry volatility, including the recent and pronounced decline in drilling activity, as well as the demanding nature of the work, many workers have left the oilfield services industry to pursue employment in different fields. Our ability to expand our operations, including through the ESCO Acquisition, depends in part on our ability to increase the size of our skilled labor force. In addition, our ability to be productive and profitable will depend upon our ability to retain skilled workers. The demand for skilled workers is high and the supply is limited. As a result, competition for experienced oilfield service personnel is intense, and we face significant challenges in competing for crews and management with large and well‑established competitors. Recently, we have experienced a significant increase in labor costs, and significant continued increases in the wages paid by competing employers could result in a reduction of our skilled labor force, increases in the wage rates that we must pay, or both. If either of these events were to occur, our capacity and profitability could be diminished and our growth potential could be impaired.

In addition, we require full compliance with the Immigration Reform and Control Act of 1986 and other laws concerning immigration and the hiring of legally documented workers. We recognize that foreign nationals may be a valuable source of talent, but that not all foreign nationals are authorized to work for U.S. companies immediately. In some cases, it may be necessary to obtain a required work authorization from the U.S. Department of Homeland Security or similar government agency prior to a foreign national working as an employee for us. Although we do not know of any issues with our employees, we could lose employees or be subject to an enforcement action that may have a material adverse effect on our business, liquidity position, financial condition, prospects and results of operations. We are also subject to the Fair Labor Standards Act, which governs such matters as minimum wage, overtime and other working conditions.

Delays or restrictions in obtaining permits by us for our operations or by our customers for their operations could impair our business.

In most states, our operations and the operations of our customers require permits from one or more governmental agencies in order to perform drilling and completion activities, secure water rights, or other regulated activities. Such permits are typically issued by state agencies, but federal and local governmental permits may also be required. The requirements for such permits vary depending on the location where such regulated activities will be conducted. As with all governmental permitting processes, there is a degree of uncertainty as to whether a permit will be granted, the time it will take for a permit to be issued, and the conditions that may be imposed in connection with the granting of the permit. In addition, some of our customers’ drilling and completion activities may take place on federal land or Native American lands, requiring leases and other approvals from the federal government or Native American tribes to conduct such drilling and completion activities or other regulated activities. Under certain circumstances, federal agencies may cancel proposed leases for federal lands and refuse to grant or delay required approvals. Therefore, our customers’ operations in certain areas of the United States may be interrupted or suspended for varying lengths of time, causing a loss of revenues to us and adversely affecting our results of operations in support of those customers.

Federal or state legislative and regulatory initiatives related to induced seismicity could result in operating restrictions or delays in the drilling and completion of oil and natural gas wells that may reduce demand for our services and could have a material adverse effect on our business, liquidity position, financial condition, prospects and results of operations.

Our oil and natural gas customers dispose of flowback and produced water or certain other oilfield fluids gathered from oil and natural gas producing operations in accordance with permits issued by government authorities overseeing such disposal activities. While these permits are issued pursuant to existing laws and regulations, these legal requirements are subject to change based on concerns of the public or governmental authorities regarding such disposal

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activities. One such concern relates to recent seismic events near underground disposal wells used for the disposal by injection of flow back and produced water or certain other oilfield fluids resulting from oil and natural gas activities. When caused by human activity, such events are called induced seismicity.

In March 2016, the United States Geological Survey identified six states with the most significant hazards from induced seismicity, including Oklahoma, Kansas, Texas, Colorado, New Mexico, and Arkansas. In response to concerns regarding induced seismicity, regulators in some states have imposed, or are considering imposing, additional requirements in the permitting of produced water disposal wells or otherwise to assess any relationship between seismicity and the use of such wells. For example, Oklahoma issued new rules for wastewater disposal wells in 2014 that imposed certain permitting and operating restrictions and reporting requirements on disposal wells in proximity to faults and also, from time to time, is developing and implementing plans directing certain wells where seismic incidents have occurred to restrict or suspend disposal well operations. The Texas Railroad Commission adopted similar rules in 2014. In addition, ongoing lawsuits allege that disposal well operations have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. These developments could result in additional regulation and restrictions on the use of injection wells by our customers to dispose of flowback and produced water and certain other oilfield fluids. Increased regulation and attention given to induced seismicity also could lead to greater opposition to, and litigation concerning, oil and natural gas activities utilizing injection wells for waste disposal. Any one or more of these developments may result in our customers having to limit disposal well volumes, disposal rates or locations, or require our customers or third party disposal well operators that are used to disposals of customers’ wastewater to shut down disposal wells, which developments could adversely affect our customers’ business and result in a corresponding decrease in the need for our services, which could have a material adverse effect on our business, liquidity position, financial condition, prospects and results of operations.

Changes in transportation regulations may increase our costs and negatively impact our results of operations.

We are subject to various transportation regulations including as a motor carrier by the DOT and by various federal, state and tribal agencies, whose regulations include certain permit requirements of highway and safety authorities. These regulatory authorities exercise broad powers over our trucking operations, generally governing such matters as the authorization to engage in motor carrier operations, safety, equipment testing, driver requirements and specifications and insurance requirements. The trucking industry is subject to possible regulatory and legislative changes that may impact our operations, such as changes in fuel emissions limits, hours of service regulations that govern the amount of time a driver may drive or work in any specific period, requirements for on‑board black box recorder devices or limits on vehicle weight and size. To the extent the federal government continues to develop and propose regulations relating to fuel quality, engine efficiency and greenhouse gas emissions, we may experience an increase in costs related to truck purchases and maintenance, impairment of equipment productivity, a decrease in the residual value of vehicles, unpredictable fluctuations in fuel prices and an increase in operating expenses. Increased truck traffic may contribute to deteriorating road conditions in some areas where our operations are performed.

Further, our operations could be affected by road construction, road repairs, detours and state and local regulations and ordinances restricting access to certain roads, including through routing and weight restrictions. In recent years, certain states, such as North Dakota and Texas, and certain counties have increased enforcement of weight limits on trucks used to transport raw materials, such as the fluids that we transport in connection with our fluids management services, on their public roads. It is possible that the states, counties and cities in which we operate our business may modify their laws to further reduce truck weight limits or impose curfews or other restrictions on the use of roadways. Such legislation and enforcement efforts could result in delays in, and increased costs to, transport fluids and otherwise conduct our business. Proposals to increase federal, state or local taxes, including taxes on motor fuels, are also made from time to time, and any such increase would increase our operating costs. Also, state and local regulation of permitted routes and times on specific roadways could adversely affect our operations. We cannot predict whether, or in what form, any legislative or regulatory changes or municipal ordinances applicable to our logistics operations will be enacted and to what extent any such legislation or regulations could increase our costs or otherwise adversely affect our business or operations.

We are subject to environmental and occupational health and safety laws and regulations that may expose us to significant costs and liabilities.

Our operations are subject to numerous federal, regional, state and local laws and regulations relating to protection of natural resources and the environment, occupational health and safety, air emissions and water discharges,

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and the management, transportation and disposal of solid and hazardous wastes and other materials. These laws and regulations impose numerous obligations that may impact our operations, including the acquisition of permits to conduct regulated activities, the imposition of restrictions on the types, quantities and concentrations of various substances that can be released into the environment or injected in formations in connection with oil and natural gas drilling and production activities, the incurrence of capital expenditures to mitigate or prevent releases of materials from our equipment, facilities or from customer locations where we are providing services, the imposition of substantial liabilities for pollution resulting from our operations, and the application of specific health and safety standards or criteria addressing worker protection. Any failure on our part or the part of our customers to comply with these laws and regulations could result in prohibitions or restrictions on operations, assessment of sanctions including administrative, civil and criminal penalties, issuance of corrective action orders requiring the performance of investigatory, remedial or curative activities or enjoining performance of some or all of our operations in a particular area, the occurrence of delays in the permitting or performance of projects and/or government or private claims for personal injury or property or natural resources damages.

Our business activities present risks of incurring significant environmental costs and liabilities, including costs and liabilities resulting from our handling and disposal of oilfield and other wastes, air emissions and wastewater discharges related to our operations and the historical operations and waste disposal practices of our predecessors. Moreover, accidental releases or spills may occur in the course of our operations, and we could incur significant costs and liabilities as a result of such releases or spills, including any third‑party claims for damage to property, natural resources or persons. In addition, private parties, including the owners of properties upon which we perform services and facilities where our wastes are taken for reclamation or disposal, also may have the right to pursue legal actions to enforce compliance as well as to seek damages for non‑compliance with environmental laws and regulations or for personal injury or property or natural resource damages. Some environmental laws and regulations may impose strict liability, which means that in some situations we could be exposed to liability even if our conduct was lawful at the time it occurred or the conduct of, or conditions caused by, prior operators or other third parties.

The trend in environmental regulation has been to place more restrictions and limitations on activities that may adversely affect the environment, and thus any changes in environmental laws and regulations or re‑interpretation of enforcement policies that result in more stringent and costly regulatory requirements could have a material adverse effect on our business, liquidity position, financial condition, prospects and results of operations if we are unable to pass on such increased compliance costs to our customers. Our customers may also incur increased costs or delays or restrictions in permitting or operating activities as a result of more stringent environmental laws and regulations, which may result in a curtailment of exploration, development or production activities that would reduce the demand for our services.

We provide services to customers who operate on federal and tribal lands, which are subject to additional regulations.

We provide services to companies operating on federal and tribal lands. Various federal agencies within the U.S. Department of the Interior, particularly the BLM and the Bureau of Indian Affairs, along with certain Native American tribes, promulgate and enforce regulations pertaining to oil and natural gas operations on Native American tribal lands and minerals where some of our customers operate. Such operations are subject to additional regulatory requirements, including lease provisions, drilling and production requirements, surface use restrictions, environmental standards, royalty considerations and taxes. Operations on federal and tribal lands are frequently subject to delays.

The BLM finalized a rule in March 2015 establishing standards for hydraulic fracturing on federal and American Indian lands; however, the BLM repealed this rule in December 2017. The repeal has been challenged in federal court by the state of California and environmental groups. In November 2016, the BLM finalized a rule regulating the venting and flaring of natural gas, leak detection, air emissions from equipment, well maintenance and unloading, drilling and completions and royalties potentially owed for loss of such emissions from oil and natural gas facilities producing on federal and tribal leases. The final rule became effective in January 2017 and is the subject of pending litigation filed by oil and natural gas trade associations and certain states seeking to modify or overturn the rule. In addition, in a March 28, 2017 executive order, President Trump directed the Secretary of the Interior to review these and several other BLM rules related to oil and gas operations and, if appropriate, to suspend, revise, or rescind the rules. The executive order also directs all executive agencies more broadly to review existing regulations that potentially burden the development or use of domestically produced energy resources. In December 2017, the BLM issued a final rule delaying implementation of the methane rules for one year.

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The EPA also issued a FIP to implement the Federal Minor New Source Review Program on tribal lands for oil and natural gas production. The FIP creates a permit‑by‑rule process for minor air sources that also incorporates emission limits and other requirements under various federal air quality standards, applying them to a range of equipment and processes used in oil and natural gas production. The FIP does not apply in areas of ozone non‑attainment. As a result, the EPA may impose area‑specific regulations in certain areas identified as tribal lands that may require additional emissions controls on existing equipment.

Depending on the ultimate outcome of any agency reviews and pending litigation, these regulations could result in increased compliance costs or additional operating restrictions for us and our customers, and could have a material adverse effect on our business, liquidity position, financial condition, prospects, results of operations, demand for our services and cash flows.

Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays as well as adversely affect demand for our support services.

Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, sand and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production. While we do not perform hydraulic fracturing, many of our customers do.

Hydraulic fracturing typically is regulated by state oil and natural gas commissions, but the EPA has asserted federal regulatory authority pursuant to the federal Safe Drinking Water Act over certain hydraulic fracturing activities involving the use of diesel fuel and issued permitting guidance in February 2014 that applies to such activities. Also, in May 2014, the EPA published an advanced notice of proposed rulemaking under the Toxic Substances and Control Act (“TSCA”) that would require the disclosure of chemicals used in hydraulic fracturing fluids; however, to date no further action has been taken and additional rulemaking under TSCA appears unlikely at this time. In addition, in June 2016, the EPA finalized regulations that prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants.

In December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources. The final report concluded that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources under some circumstances,” noting that the following hydraulic fracturing water cycle activities and local- or regional-scale factors are more likely than others to result in more frequent or more severe impacts: water withdrawals for fracturing in times or areas of low water availability; surface spills during the management of fracturing fluids, chemicals or produced water; injection of fracturing fluids into wells with inadequate mechanical integrity; injection of fracturing fluids directly into groundwater resources; discharge of inadequately treated fracturing wastewater to surface waters; and disposal or storage of fracturing wastewater in unlined pits. Since the report did not find a direct link between hydraulic fracturing itself and contamination of groundwater resources, this years-long study report does not appear to provide any basis for further regulation of hydraulic fracturing at the federal level.

Various state and local governments have implemented, or are considering, increased regulatory oversight of hydraulic fracturing through additional permit requirements, operational restrictions, disclosure requirements, well construction, and temporary or permanent bans on hydraulic fracturing in certain areas. In addition, state and federal regulatory agencies have recently focused on a possible connection between the disposal of wastewater in underground injection wells and the increased occurrence of seismic activity, and regulatory agencies at all levels are continuing to study the possible linkage between oil and gas activity and induced seismicity. In response to these concerns, regulators in some states are seeking to impose additional requirements on hydraulic fracturing fluid disposal practices, including restrictions on the operations of produced water disposal wells and imposing more stringent requirements on the permitting of such wells. The adoption and implementation of any new laws or regulations that restrict our customers ability to dispose of produced water could result in increased operating costs for the, which in turn could indirectly reduce demand for our services.

Local governments also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular or prohibit the performance of well drilling in general or hydraulic fracturing in particular. If new federal, state or local laws or regulations that significantly restrict hydraulic fracturing are adopted, such legal requirements could result in delays, eliminate certain drilling and injection activities and make it more difficult or costly to perform hydraulic fracturing. Any such regulations limiting or

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prohibiting hydraulic fracturing could result in decreased oil and natural gas exploration and production activities and, therefore, adversely affect demand for our services and our business. Such laws or regulations could also materially increase our costs of compliance and doing business.

Climate change legislation or regulations restricting emissions of GHGs could result in increased operating costs and reduced demand for our services.

The EPA has determined that emissions of carbon dioxide, methane and other GHGs present an endangerment to the environment because emissions of such gases are contributing to the warming of the earth’s atmosphere and other climatic changes. Based on these findings, the EPA adopted regulations that restrict emissions of GHGs under existing provisions of the federal Clean Air Act including one that requires a reduction in emissions of GHGs from motor vehicles and another that requires certain preconstruction and operating permit reviews for GHG emissions from certain large stationary sources. The EPA has also adopted rules requiring the monitoring and reporting of GHGs from specified GHG emission sources, including, among others, certain oil and natural gas production facilities, on an annual basis. More recently, in June 2016, the EPA finalized regulations under the CAA that address emissions of methane from equipment and processes across the source category, including hydraulically fractured oil and natural gas well completions, and also imposes leak detection and repair requirements on operators. However, in June 2017 the EPA published a proposed rule to stay certain portions of the June 2016 standards for two years and re-consider the entirety of the 2016 methane standards. The EPA has not yet published a final rule and, as a result, the 2016 rule remains in effect but the future implementation of that rule is uncertain at this time.

To date, there has been no federal legislation to reduce emissions of GHGs; however, almost one-half of the states have established GHG cap and trade programs. Most of these cap and trade programs work by requiring major sources of emissions or major producers of fuels, to acquire and surrender emission allowances, the number of which is reduced each year of the program. In addition, in 2015, the U.S. participated in the United Nations Conference on Climate Change, which led to the creation of the Paris Agreement. The Paris Agreement required participating nation to show further reductions in their GHG emissions. Following the change in U.S. Presidential Administrations, the United States issued formal notice to the United Nations in August 2017 that it was withdrawing from the Paris Agreement. The Paris Agreement has a four year exit process but the United States’ adherence to this process is uncertain at this time.

Any new federal, regional or state restrictions on emissions of GHGs that may be imposed in areas in which we conduct business could result in increased compliance costs or additional operating restrictions on our customers. Such actions could also potentially make our customers’ products more expensive and thus reduce demand for those products, which could have a material adverse effect on the demand for our services and our business. Recently, activists concerned about the potential effects of climate change have directed their attention at sources of funding for fossil-fuel energy companies, which has resulted in certain financial institutions, funds and other sources of capital restricting or eliminating their investment in oil and natural gas activities. Ultimately, this could make it more difficult to secure funding for exploration and production activities, which could have an adverse effect on our business and results of operations. Notwithstanding potential risks related to climate change, the International Energy Agency estimates that global energy demand will continue to rise and will not peak until after 2040 and that oil and gas will continue to represent a substantial percentage of global energy use over that time. Finally, some scientists have concluded that increasing concentrations of GHGs in the earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic events. If any such effects were to occur, they could have an adverse effect on our results of operations if they were to damage our equipment or facilities.

Any future indebtedness could adversely affect our financial condition.

As of December 31, 2017, we had $7.1 million indebtedness outstanding and $21.9 million of available borrowing capacity under our senior secured revolving credit facility (the “Credit Facility”).

In addition, subject to the limits contained in our Credit Facility, we may incur substantial additional debt from time to time. Any borrowings we may incur in the future would have several important consequences for our future operations, including that:

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covenants contained in the documents governing such indebtedness may require us to meet or maintain certain financial tests, which may affect our flexibility in planning for, and reacting to, changes in our industry, such as being able to take advantage of acquisition opportunities when they arise;

our ability to obtain additional financing for working capital, capital expenditures, acquisitions, general corporate and other purposes may be limited;

we may be competitively disadvantaged compared to our competitors that have greater access to capital resources; and

we may be more vulnerable to adverse economic and industry conditions.

If we incur indebtedness in the future, we may have significant principal payments due at specified future dates under the documents governing such indebtedness. Our ability to meet such principal obligations will be dependent upon future performance, which in turn will be subject to general economic conditions, industry cycles and financial, business and other factors affecting our operations, many of which are beyond our control. Our business may not continue to generate sufficient cash flow from operations to repay any incurred indebtedness. If we are unable to generate sufficient cash flow from operations, we may be required to sell assets, to refinance all or a portion of such indebtedness or to obtain additional financing.

Our Credit Facility subjects us to various financial and other restrictive covenants. Ranger Services had difficulty maintaining compliance with the covenants and ratios required under the Ranger Line of Credit and Ranger Note and we may have similar difficulties with the new Credit Facility. These restrictions may limit our operational or financial flexibility and could subject us to potential defaults under our Credit Facility.

Our Credit Facility subjects us to significant financial and other restrictive covenants, including, but not limited to, restrictions on incurring additional debt and certain distributions. Our ability to comply with these financial condition tests can be affected by events beyond our control and we may not be able to do so.

Our Credit Facility contains certain financial covenants, including a certain minimum fixed charge coverage ratio during certain testing periods. Please see “Management’s Discussion and Analysis of Financial Condition and Results of Operation—Liquidity and Capital Resources—Our Debt Agreements.”

If we are unable to remain in compliance with the financial covenants of our Credit Facility, then amounts outstanding thereunder may be accelerated and become due immediately. Any such acceleration could have a material adverse effect on our business, liquidity position, financial condition, prospects and results of operations.

In the event that we are unable to access sufficient capital to fund our business and planned capital expenditures, we may be required to curtail potential acquisitions, strategic growth projects, portions of our current operations and other activities. A lack of capital could result in a decrease in our operations, subject us to claims of breach under customer and supplier contracts and may force us to sell some of our assets or issue additional equity on an untimely or unfavorable basis, each of which could adversely affect our business, financial condition, results of operations and cash flows.

Increases in interest rates could adversely impact the price of our shares, our ability to issue equity or incur debt for acquisitions or other purposes.

Interest rates on future borrowings, credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly. Changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our shares, and a rising interest rate environment could have an adverse impact on the price of our shares, our ability to issue equity or incur debt for acquisitions or other purposes.

Fuel conservation measures could reduce demand for oil and natural gas which would in turn reduce the demand for our services.

Fuel conservation measures, alternative fuel requirements and increasing consumer demand for alternatives to oil and natural gas could reduce demand for oil and natural gas. The impact of the changing demand for oil and natural

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gas may have a material adverse effect on our business, liquidity position, financial condition, prospects and results of operations. Additionally, the increased competitiveness of alternative energy sources (such as wind, solar geothermal, tidal, and biofuels) could reduce demand for hydrocarbons and therefore for our services, which would lead to a reduction in our revenues.

Unsatisfactory safety performance may negatively affect our customer relationships and, to the extent we fail to retain existing customers or attract new customers, adversely impact our revenues.

Our ability to retain existing customers and attract new business is dependent on many factors, including our ability to demonstrate that we can reliably and safely operate our business in a manner that is consistent with applicable laws, rules and permits, which legal requirements are subject to change. Existing and potential customers consider the safety record of their third‑party service providers to be of high importance in their decision to engage such providers. If one or more accidents were to occur at one of our operating sites, the affected customer may seek to terminate or cancel its use of our equipment or services and may be less likely to continue to use our services, which could cause us to lose substantial revenues. Furthermore, our ability to attract new customers may be impaired if they view our safety record as unacceptable. In addition, it is possible that we will experience multiple or particularly severe accidents in the future, causing our safety record to deteriorate. This may be more likely as we continue to grow, if we experience high employee turnover or labor shortage, or hire inexperienced personnel to bolster our staffing needs.

The Endangered Species Act and Migratory Bird Treaty Act and other restrictions intended to protect certain species of wildlife govern our and our customers’ operations and additional restrictions may be imposed in the future, which constraints could have an adverse impact on our ability to expand some of our existing operations or limit our customers’ ability to develop new oil and natural gas wells.

Oil and natural gas operations in our operating areas can be adversely affected by seasonal or permanent restrictions on drilling activities designed to protect various wildlife, which may limit our ability to operate in protected areas. Permanent restrictions imposed to protect endangered species could prohibit drilling in certain areas or require the implementation of expensive mitigation measures.

For example, the Endangered Species Act (the “ESA”) restricts activities that may affect endangered or threatened species or their habitats and provides for substantial penalties in cases where covered species are killed or injured. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act (the “MBTA”). To the extent species that are listed under the ESA or similar state laws, or are protected under the MBTA, or the designation of previously unprotected species as threatened or endangered in areas where we or our customers operate could cause us or our customers to incur increased costs arising from species protection measures and could result in delays or limitations in our or our customers’ performance of operations, which could adversely affect or reduce demand for our services.

We rely on a few key employees whose absence or loss could adversely affect our business.

Many key responsibilities within our business have been assigned to a small number of employees. The loss of their services could adversely affect our business. In particular, the loss of the services of one or more members of our executive team, including our President and Chief Executive Officer or Chief Financial Officer, could disrupt our operations. We do not maintain “key person” life insurance policies on any of our employees. As a result, we are not insured against any losses resulting from the death of our key employees.

We may be subject to claims for personal injury and property damage, which could materially adversely affect our financial condition, prospects and results of operations.

Our services are subject to inherent risks that can cause personal injury or loss of life, damage to or destruction of property, equipment or the environment or the suspension of our operations. Litigation arising from operations where our services are provided may cause us to be named as a defendant in lawsuits asserting potentially large claims including claims for exemplary damages. We maintain what we believe is customary and reasonable insurance to protect our business against these potential losses, but such insurance may not be adequate to cover our liabilities, and we are not fully insured against all risks.

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In addition, and subject to certain exceptions, our customers typically assume responsibility for, including control and removal of, all other pollution or contamination which may occur during operations, including that which may result from seepage or any other uncontrolled flow of drilling and completion fluids. We may have liability in such cases if we are negligent or commit willful acts. Our customers generally agree to indemnify us against claims arising from their employees’ personal injury or death to the extent that, in the case of our operations, their employees are injured or their properties are damaged by such operations, unless resulting from our gross negligence or willful misconduct. Our customers also generally agree to indemnify us for loss or destruction of customer‑owned property or equipment. In turn, we agree to indemnify our customers for loss or destruction of property or equipment we own and for liabilities arising from personal injury to or death of any of our employees, unless resulting from gross negligence or willful misconduct of the customer. However, we might not succeed in enforcing such contractual allocation or might incur an unforeseen liability falling outside the scope of such allocation. As a result, we may incur substantial losses which could materially and adversely affect our financial condition and results of operation.

Anti‑indemnity provisions enacted by many states may restrict or prohibit a party’s indemnification of us.

We typically enter into agreements with our customers governing the provision of our services, which usually include certain indemnification provisions for losses resulting from operations. Such agreements may require each party to indemnify the other against certain claims regardless of the negligence or other fault of the indemnified party; however, many states place limitations on contractual indemnity agreements, particularly agreements that indemnify a party against the consequences of its own negligence. Furthermore, certain states, including Louisiana, New Mexico, Texas and Wyoming, have enacted statutes generally referred to as “oilfield anti‑indemnity acts” expressly prohibiting certain indemnity agreements contained in or related to oilfield services agreements. Such anti‑indemnity acts may restrict or void a party’s indemnification of us, which could have a material adverse effect on our business, liquidity position, financial condition, prospects and results of operations.

Seasonal weather conditions and natural disasters could severely disrupt normal operations and harm our business.

Our operations are located in different regions of the United States. Some of these areas, including the Denver‑Julesburg Basin and the Bakken Shale, are adversely affected by seasonal weather conditions, primarily in the winter and spring. During periods of heavy snow, ice, wind or rain, we may be unable to move our equipment between locations, thereby reducing our ability to provide services and generate revenues, or we could suffer weather‑related damage to our facilities and equipment, resulting in delays in operations. The exploration activities of our customers may also be affected during such periods of adverse weather conditions. Additionally, extended drought conditions in our operating regions could impact our ability or our customers’ ability to source sufficient water or increase the cost for such water. As a result, a natural disaster or inclement weather conditions could severely disrupt the normal operation of our business and adversely impact our financial condition and results of operations.

In addition, some scientists have concluded that increasing concentrations of GHGs in the atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climate events that could have an adverse effect on our operations and the operations of our customers.

If we are unable to fully protect our intellectual property rights, or if any disputes regarding intellectual property rights arise with third parties, we may suffer a loss in our competitive advantage or market share.

We do not have patents or patent applications relating to many of our key processes and technology. If we are not able to maintain the confidentiality of our trade secrets, or if our competitors are able to replicate our technology or services, our competitive advantage would be diminished. We cannot assure you we will be able to prevent our competitors from employing comparable technologies or processes.

In addition, third parties from time to time may initiate litigation against us by asserting that the conduct of our business infringes, misappropriates or otherwise violates intellectual property rights. If we are sued for infringement and lose, we could be required to pay substantial damages and/or be enjoined from using or selling the infringing products or technology. Any legal proceeding concerning intellectual property could be protracted and costly regardless of the merits of any claim and is inherently unpredictable and could have a material adverse effect on our financial condition, regardless of its outcome.

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Additionally, we currently license certain third party intellectual property in connection with our business, and the loss of any such license could adversely impact our financial condition and results of operations.

We may be subject to interruptions or failures in our information technology systems.

We rely on sophisticated information technology systems and infrastructure to support our business, including process control technology. Any of these systems may be susceptible to outages due to fire, floods, power loss, telecommunications failures, usage errors by employees, computer viruses, cyber‑attacks or other security breaches, or similar events. The failure of any of our information technology systems may cause disruptions in our operations, which could adversely affect our revenues and profitability.

We are subject to cyber security risks. A cyber incident could occur and result in information theft, data corruption, operational disruption and/or financial loss.

The oil and natural gas industry has become increasingly dependent on digital technologies to conduct certain processing activities. For example, we depend on digital technologies to perform many of our services and to process and record financial and operating data. At the same time, cyber incidents, including deliberate attacks, have increased. The U.S. government has issued public warnings that indicate that energy assets might be specific targets of cyber security threats. Our technologies, systems and networks, and those of our vendors, suppliers and other business partners, may become the target of cyberattacks or information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information, or other disruption of business operations. In addition, certain cyber incidents, such as surveillance, may remain undetected for an extended period. Our systems and insurance coverage for protecting against cyber security risks may not be sufficient. As the sophistication of cyber incidents continues to evolve, we will likely be required to expend additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyber incidents. Our insurance coverage for cyberattacks may not be sufficient to cover all the losses we may experience as a result of such cyberattacks.

A terrorist attack or armed conflict could harm our business.

The occurrence or threat of terrorist attacks in the United States or other countries, anti‑terrorist efforts and other armed conflicts involving the United States or other countries, including continued hostilities in the Middle East, may adversely affect the United States and global economies and could prevent us from meeting our financial and other obligations. If any of these events occur, the resulting political instability and societal disruption could reduce overall demand for oil and natural gas, potentially putting downward pressure on demand for our services and causing a reduction in our revenues. Oil and natural gas‑related facilities could be direct targets of terrorist attacks, and our operations could be adversely impacted if infrastructure integral to our customers’ operations is destroyed or damaged. Costs for insurance and other security may increase as a result of these threats, and some insurance coverage may become more difficult to obtain, if available at all.

We may record losses or impairment charges related to idle assets or assets that we sell.

Prolonged periods of low utilization, changes in technology or the sale of assets below their carrying value may cause us to experience losses in our results of operations. These events could result in the recognition of impairment charges that negatively impact our financial results. Significant impairment charges as a result of a decline in market conditions or otherwise could have a material adverse effect on our results of operations in future periods.

Risks Related to Our Class A Common Stock

 

Being a public company requires compliance with the reporting requirements of the Exchange Act“”, and the requirements of Sarbanes-Oxley Act of 2002 (“Sarbanes-Oxley”), which may strain our resources, increase our costs and distract management, and we may be unable to comply with these requirements in a timely or cost-effective manner.

 

As a public company, we must comply with laws, regulations and requirements, certain corporate governance provisions of Sarbanes-Oxley, related regulations of the SEC and the requirements of the NYSE. Complying with these

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statutes, regulations and requirements occupies a significant amount of time of our Board of Directors and management and significantly increases our costs and expenses. We have:

·

instituted a more comprehensive compliance function; 

·

complied with rules promulgated by the NYSE; 

·

continued to prepare and distributed periodic public reports in compliance with our obligations under the federal securities laws; 

·

established new internal policies, such as those relating to insider trading; and 

·

involved and retained to a greater degree outside counsel and accountants in the above activities.

Furthermore, while we generally must comply with Section 404 of Sarbanes-Oxley for our fiscal year ending December 31, 2018, we are not required to have our independent registered public accounting firm attest to the effectiveness of our internal controls until our first annual report subsequent to our ceasing to be an “emerging growth company” within the meaning of Section 2(a)(19) of the Securities Act. Accordingly, we may not be required to have our independent registered public accounting firm attest to the effectiveness of our internal controls until as late as our Annual Report for the fiscal year ending December 31, 2022. Once it is required to do so, our independent registered public accounting firm may issue a report that is adverse in the event it is not satisfied with the level at which our controls are documented, designed, operated or reviewed. Compliance with these requirements may strain our resources, increase our costs and distract management, and we may be unable to comply with these requirements in a timely or cost-effective manner.

 

In addition, being a public company subject to these rules and regulations may make it more difficult and more expensive for us to obtain director and officer liability insurance and we may be required to accept reduced policy limits and coverage or incur substantially higher costs to obtain the same or similar coverage. As a result, it may be more difficult for us to attract and retain qualified individuals to serve on our Board of Directors or as executive officers.

 

We have identified a material weakness in our internal control over financial reporting and may identify additional material weaknesses in the future or otherwise fail to maintain an effective system of internal controls, which may result in material misstatements of our financial statements or cause us to fail to meet our periodic reporting obligations.

 

As a public company, we are required to maintain internal control over financial reporting and to report any material weaknesses in those internal controls, subject to any exemptions that we avail ourselves to under the Jumpstart Our Business Startups Act of 2012 (the “JOBS Act”). For example, we are required to perform system and process evaluation and testing of our internal control over financial reporting to allow management to report on the effectiveness of our internal control over financial reporting, as required by Section 404 of Sarbanes-Oxley, for our fiscal year ending December 31, 2018. We are in the process of designing, implementing, and testing internal control over financial reporting required to comply with this obligation.

 

We and our independent auditors identified material weaknesses in internal control over financial reporting for the year ended December 31, 2017 in addition to the previously disclosed material weakness for the year ended December 31, 2016. A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting such that there is a reasonable possibility that a material misstatement of our annual or interim financial statements will not be prevented or detected on a timely basis. The material weaknesses each related to the lack of sufficient qualified accounting personnel, which led to the incorrect application of generally accepted accounting principles, ineffective controls over accounting for non-routine and/or complex transactions, and ineffective controls over the financial statement close and reporting processes. 

 

Our failure to implement and maintain effective internal control over financial reporting could result in errors in our financial statements that could result in a restatement of our financial statements and cause us to fail to meet our reporting obligations. Ineffective internal controls could also cause investors to lose confidence in our reported financial information, which could have a negative effect on the trading price of our Class A Common Stock.

 

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CSL has the ability to direct the voting of a majority of our voting stock, and their interests may conflict with those of our other shareholders.

 

The Existing Owners, CSL Opportunities II, CSL Holdings II and CSL Energy Opportunities Master Fund, LLC (“CSL Master Fund”) own approximately 60.4% of our voting interests. CSL holds a majority of the voting interests in each of the Existing Owners, CSL Opportunities II, CSL Holdings II and CSL Master Fund. CSL and its affiliates beneficially own an aggregate of approximately 2,818,350 shares of Class A Common Stock, 6,416,154 units in Ranger LLC (“Ranger Units”) and 6,416,154 shares of our Class B Common Stock, par value $0.01 per share (“Class B Common Stock”). CSL’s beneficial ownership of greater than 50% of our voting stock means CSL will be able to control matters requiring shareholder approval, including the election of directors (other than certain rights of Bayou Holdings to designate nominees to our Board of Directors as discussed further herein), changes to our organizational documents and significant corporate transactions. This concentration of ownership makes it unlikely that any other holder or group of holders of our Class A Common Stock (other than Bayou Holdings) will be able to affect the way we are managed or the direction of our business. Further, we entered into a stockholders’ agreement with the Existing Owners and Bayou Holdings, CSL Opportunities II and CSL Holdings II (together, the “Bridge Loan Lenders”)the Bridge Loan Lenders. Among other things, the stockholders’ agreement provides (i) CSL with the right to designate a certain number of nominees to our Board of Directors for so long as CSL beneficially owns at least 10% of our common stock and (ii) Bayou Holdings with the right to designate two nominees to our Board of Directors for so long as CSL beneficially owns at least 50% of our common stock. The interests of CSL and Bayou Holdings with respect to matters potentially or actually involving or affecting us, such as future acquisitions, financings and other corporate opportunities and attempts to acquire us, may conflict with the interests of our other shareholders.

 

For example, CSL and Bayou Holdings may have different tax positions from us, especially in light of the Tax Receivable Agreement we entered into with certain of our stockholders in connection with the Offering (the “Tax Receivable Agreement”), that could influence their decisions regarding whether and when to support the disposition of assets, the incurrence or refinancing of new or existing indebtedness, or the termination of the Tax Receivable Agreement and the acceleration of our obligations thereunder. In addition, the determination of future tax reporting positions, the structuring of future transactions and the handling of any challenge by any taxing authority to our tax reporting positions may take into consideration CSL’s or Bayou Holdings’ tax or other considerations that may differ from the considerations of us or our other shareholders.”

 

Given this concentrated ownership, CSL (and, in certain circumstances, Bayou Holdings) would have to approve any potential acquisition of us. The existence of a significant shareholder and the stockholders’ agreement may have the effect of deterring hostile takeovers, delaying or preventing changes in control or changes in management, or limiting the ability of our other shareholders to approve transactions that they may deem to be in the best interests of our company. Moreover, CSL’s concentration of stock ownership may adversely affect the trading price of our Class A Common Stock to the extent investors perceive a disadvantage in owning stock of a company with a significant shareholder. 

 

 

Certain of our executive officers and directors have significant duties with, and spend significant time serving, entities that may compete with us in seeking acquisitions and business opportunities and, accordingly, may have conflicts of interest in allocating time or pursuing business opportunities.

 

Certain of our executive officers and directors, who are responsible for managing the direction of our operations, hold positions of responsibility with other entities (including affiliated entities) that are in the oil and natural gas industry. These executive officers and directors may become aware of business opportunities that may be appropriate for presentation to us as well as to the other entities with which they are or may become affiliated. Due to these existing and potential future affiliations, these individuals may present potential business opportunities to other entities prior to presenting them to us, which could cause additional conflicts of interest. They may also decide that certain opportunities are more appropriate for other entities with which they are affiliated, and as a result, they may elect not to present those opportunities to us. These conflicts may not be resolved in our favor.

 

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CSL, Bayou Holdings and their respective affiliates are not limited in their ability to compete with us, and the corporate opportunity provisions in our amended and restated certificate of incorporation could enable CSL and Bayou Holdings to benefit from corporate opportunities that might otherwise be available to us.

 

Our governing documents provide that CSL, Bayou Holdings and their respective affiliates (including portfolio investments of CSL and its affiliates) are not restricted from owning assets or engaging in businesses that compete directly or indirectly with us. In particular, subject to the limitations of applicable law, our amended and restated certificate of incorporation, among other things:

 

·

permits CSL, Bayou Holdings and their respective affiliates to conduct business that competes with us and to make investments in any kind of property in which we may make investments; and 

·

provides that if CSL, Bayou Holdings or their respective affiliates, or any employee, partner, member, manager, officer or director of CSL, Bayou Holdings or their respective affiliates who is also one of our directors or officers, becomes aware of a potential business opportunity, transaction or other matter, they will have no duty to communicate or offer that opportunity to us.

CSL, Bayou Holdings or their respective affiliates may become aware, from time to time, of certain business opportunities (such as acquisition opportunities) and may direct such opportunities to other businesses in which they have invested, in which case we may not become aware of or otherwise have the ability to pursue such opportunity. Furthermore, such businesses may choose to compete with us for these opportunities, possibly causing these opportunities to not be available to us or causing them to be more expensive for us to pursue. In addition, CSL, Bayou Holdings and their respective affiliates may dispose of equipment or other assets in the future, without any obligation to offer us the opportunity to purchase any of those assets. As a result, our renouncing our interest and expectancy in any business opportunity that may be from time to time presented to CSL, Bayou Holdings and their respective affiliates could adversely impact our business or prospects if attractive business opportunities are procured by such parties for their own benefit rather than for ours.

 

A significant reduction by CSL of its ownership interests in us could adversely affect us.

 

We believe that CSL’s ownership interest in us provides it with an economic incentive to assist us to be successful. CSL is not subject to any obligation to maintain its ownership interest in us and may elect at any time to sell all or a substantial portion of or otherwise reduce its ownership interest in us. If CSL sells all or a substantial portion of its ownership interest in us, it may have less incentive to assist in our success and its affiliate(s) that are expected to serve as members of our Board of Directors may resign. Such actions could adversely affect our ability to successfully implement our business strategies which could adversely affect our cash flows or results of operations.

 

Our amended and restated certificate of incorporation and amended and restated bylaws, as well as Delaware law, contain provisions that could discourage acquisition bids or merger proposals, which may adversely affect the market price of our Class A Common Stock and could deprive our investors of the opportunity to receive a premium for their shares.

 

Our amended and restated certificate of incorporation authorizes our Board of Directors to issue preferred stock without shareholder approval in one or more series, designate the number of shares constituting any series, and fix the rights, preferences, privileges and restrictions thereof, including dividend rights, voting rights, rights and terms of redemption, redemption price or prices and liquidation preferences of such series. If our Board of Directors elects to issue preferred stock, it could be more difficult for a third party to acquire us. In addition, some provisions of our amended and restated certificate of incorporation and amended and restated bylaws could make it more difficult for a third party to acquire control of us, even if the change of control would be beneficial to our shareholders. These provisions include:

 

·

after CSL and its affiliates no longer collectively hold more than 50% of the voting power of our common stock, dividing our Board of Directors into three classes of directors, with each class serving staggered three-year terms; 

·

after CSL and its affiliates no longer collectively hold more than 50% of the voting power of our common stock, providing that all vacancies, including newly created directorships, may, except as otherwise

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required by law or, if applicable, the rights of holders of a series of preferred stock, only be filled by the affirmative vote of a majority of directors then in office, even if less than a quorum (prior to such time, vacancies may also be filled by shareholders holding a majority of the outstanding shares entitled to vote); 

·

after CSL and its affiliates no longer collectively hold more than 50% of the voting power of our common stock, permitting any action by shareholders to be taken only at an annual meeting or special meeting rather than by a written consent of the shareholders, subject to the rights of any series of preferred stock with respect to such rights; 

·

after CSL and its affiliates no longer collectively hold more than 50% of the voting power of our common stock, permitting special meetings of our shareholders to be called only by our Board of Directors pursuant to a resolution adopted by the affirmative vote of a majority of the total number of authorized directors whether or not there exist any vacancies in previously authorized directorships (prior to such time, a special meeting may also be called at the request of shareholders holding a majority of the outstanding shares entitled to vote); 

·

after CSL and its affiliates no longer collectively hold more than 50% of the voting power of our common stock, requiring the affirmative vote of the holders of at least 662/3% in voting power of all then outstanding common stock entitled to vote generally in the election of directors, voting together as a single class, to remove any or all of the directors from office at any time, and directors will be removable only for “cause”; 

·

prohibiting cumulative voting in the election of directors; 

·

establishing advance notice provisions for shareholder proposals and nominations for elections to the board of directors to be acted upon at meetings of shareholders; and 

·

providing that the Board of Directors is expressly authorized to adopt, or to alter or repeal our bylaws.

In addition, certain change of control events have the effect of accelerating the payment due under the Tax Receivable Agreement, which could be substantial and accordingly serve as a deterrent to a potential acquirer of our company. Please see “—Risks Related to Our Resulting Structure—In certain cases, payments under the Tax Receivable Agreement may be accelerated and/or significantly exceed the actual benefits, if any, we realize in respect of the tax attributes subject to the Tax Receivable Agreement.”

 

Our amended and restated certificate of incorporation designates the Court of Chancery of the State of Delaware as the sole and exclusive forum for certain types of actions and proceedings that may be initiated by our shareholders, which could limit our shareholders’ ability to obtain a favorable judicial forum for disputes with us or our directors, officers, employees or agents.

 

Our amended and restated certificate of incorporation provides that, unless we consent in writing to the selection of an alternative forum, the Court of Chancery of the State of Delaware is, to the fullest extent permitted by applicable law, the sole and exclusive forum for (i) any derivative action or proceeding brought on our behalf, (ii) any action asserting a claim of breach of a fiduciary duty owed by any of our directors, officers, employees or agents to us or our shareholders, (iii) any action asserting a claim arising pursuant to any provision of the Delaware General Corporation Law (the “DGCL”), our amended and restated certificate of incorporation or our amended and restated bylaws, or (iv) any action asserting a claim against us that is governed by the internal affairs doctrine, in each such case subject to such Court of Chancery having personal jurisdiction over the indispensable parties named as defendants therein. Any person or entity purchasing or otherwise acquiring any interest in shares of our capital stock will be deemed to have notice of, and consented to, the provisions of our amended and restated certificate of incorporation described in the preceding sentence. This choice of forum provision may limit a shareholder’s ability to bring a claim in a judicial forum that it considers more likely to be favorable for disputes with us or our directors, officers, employees or agents, which may discourage such lawsuits against us and such persons. Alternatively, if a court were to find these provisions of our amended and restated certificate of incorporation inapplicable to, or unenforceable in respect of, one or more of the specified types of actions or proceedings, we may incur additional costs associated with resolving such matters in other jurisdictions, which could adversely affect our business, financial condition, prospects or results of operations.

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We do not intend to pay cash dividends on our Class A Common Stock, and our Credit Facility places certain restrictions on our ability to do so. Consequently, your only opportunity to achieve a return on your investment is if the price of our Class A Common Stock appreciates.

 

We do not plan to declare cash dividends on shares of our Class A Common Stock in the foreseeable future. Additionally, our Credit Facility places certain restrictions on our ability to pay cash dividends. Consequently, your only opportunity to achieve a return on your investment in us will be if you sell your Class A Common Stock at a price greater than you paid for it. There is no guarantee that the price of our Class A Common Stock that will prevail in the market will ever exceed the price that you paid for it.

 

Future sales of our Class A Common Stock in the public market, or the perception that such sales may occur, could reduce our stock price, and any additional capital raised by us through the sale of equity or convertible securities may dilute your ownership in us.

 

We may sell additional shares of Class A Common Stock or securities convertible into Class A Common Stock in subsequent public offerings. As of March 1, 2018, we had outstanding 8,413,178 shares of Class A Common Stock, which may be resold immediately in the public market. As of March 1, 2018, the Existing Owners and the Bridge Loan Lenders owned 6,866,154 shares of our Class B Common Stock. The Existing Owners and the Bridge Loan Lenders are parties to a registration rights agreement, which require us to effect the registration of any shares of Class A Common Stock held by an Existing Owner or Bridge Loan Lender or that an Existing Owner or Bridge Loan Lender receives upon redemption of its shares of Class B Common Stock.

 

In connection with the Offering, we filed a registration statement with the SEC on Form S-8 providing for the registration of 1,250,000 shares of our Class A Common Stock issued or reserved for issuance under our long term incentive plan. Subject to the satisfaction of vesting conditions, the expiration of lock-up agreements and the requirements of Rule 144, shares registered under the registration statement on Form S-8 are available for resale immediately in the public market without restriction.

 

We cannot predict the size of future issuances of our Class A Common Stock or securities convertible into Class A Common Stock or the effect, if any, that future issuances and sales of shares of our Class A Common Stock will have on the market price of our Class A Common Stock. Sales of substantial amounts of our Class A Common Stock (including shares issued in connection with the ESCO Acquisition or other acquisitions), or the perception that such sales could occur, may adversely affect prevailing market prices of our Class A Common Stock.

 

We may issue preferred stock, the terms of which could adversely affect the voting power or value of our Class A Common Stock.

 

Our amended and restated certificate of incorporation authorizes us to issue, without the approval of our shareholders, one or more classes or series of preferred stock having such designations, preferences, limitations and relative rights, including preferences over our Class A Common Stock respecting dividends and distributions, as our Board of Directors may determine. The terms of one or more classes or series of preferred stock could adversely impact the voting power or value of our Class A Common Stock. For example, we might grant holders of preferred stock the right to elect some number of our directors in all events or on the happening of specified events or the right to veto specified transactions. Similarly, the repurchase or redemption rights or liquidation preferences we might assign to holders of preferred stock could affect the residual value of the Class A Common Stock.

 

We are a “controlled company” within the meaning of NYSE rules and, as a result, qualify for and intend to rely on exemptions from certain corporate governance requirements.

 

CSL, through its interests in the Existing Owners, CSL Opportunities II, CSL Holdings II and CSL Master Fund hold a majority of the voting power of our capital stock. As a result, we are a controlled company within the meaning of NYSE corporate governance standards. Under NYSE rules, a company of which more than 50% of the voting power for the election of directors is held by an individual, a group or another company is a controlled company and may elect not to comply with certain NYSE corporate governance requirements, including the requirements that:

 

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·

a majority of the Board of Directors consist of independent directors as defined under the rules of the NYSE;

·

the nominating and governance committee be composed entirely of independent directors with a written charter addressing the committee’s purpose and responsibilities; and

·

the compensation committee be composed entirely of independent directors with a written charter addressing the committee’s purpose and responsibilities.

These requirements will not apply to us as long as we remain a controlled company. Since our initial offering we have utilized some or all of these exemptions. Accordingly, you may not have the same protections afforded to shareholders of companies that are subject to all of the corporate governance requirements of the NYSE.

 

For as long as we are an emerging growth company, we will not be required to comply with certain reporting requirements, including those relating to accounting standards and disclosure about our executive compensation, that apply to other public companies.

 

We are classified as an “emerging growth company” under the JOBS Act. For as long as we are an emerging growth company, which may be up to five full fiscal years, unlike other public companies, we will not be required to, among other things: (i) provide an auditor’s attestation report on management’s assessment of the effectiveness of our system of internal control over financial reporting pursuant to Section 404(b) of Sarbanes-Oxley; (ii) comply with any new requirements adopted by the Public Company Accounting Oversight Board (United States) (“PCAOB”) requiring mandatory audit firm rotation or a supplement to the auditor’s report in which the auditor would be required to provide additional information about the audit and the financial statements of the issuer; (iii) provide certain disclosures regarding executive compensation required of larger public companies; or (iv) hold nonbinding advisory votes on executive compensation. We will remain an emerging growth company for up to five years, although we will lose that status sooner if we have more than $1.07 billion of revenues in a fiscal year, have more than $700.0 million in market value of our Class A Common Stock held by non-affiliates, or issue more than $1.0 billion of non-convertible debt over a three-year period.

 

To the extent that we rely on any of the exemptions available to emerging growth companies, you will receive less information about our executive compensation and internal control over financial reporting than issuers that are not emerging growth companies. If some investors find our Class A Common Stock to be less attractive as a result, there may be a less active trading market for our Class A Common Stock and our stock price may be more volatile.

 

If securities or industry analysts do not publish research or reports about our business, if they adversely change their recommendations regarding our Class A Common Stock or if our operating results do not meet their expectations, our stock price could decline.

 

The trading market for our Class A Common Stock will be influenced by the research and reports that industry or securities analysts publish about us or our business. If one or more of these analysts cease coverage of our company or fail to publish reports on us regularly, we could lose visibility in the financial markets, which in turn could cause our stock price or trading volume to decline. Moreover, if one or more of the analysts who cover our company adversely changes his or her recommendation with respect to our Class A Common Stock or if our operating results do not meet their expectations, our stock price could decline.

 

 

Risks Related to Our Structure 

 

We are a holding company. Our sole material asset is our equity interest in Ranger LLC and we are accordingly dependent upon distributions from Ranger LLC to pay taxes, make payments under the Tax Receivable Agreement and cover our corporate and other overhead expenses.

 

We are a holding company and have no material assets other than our equity interest in Ranger LLC. We have no independent means of generating revenues. To the extent Ranger LLC has available cash, we intend to cause Ranger LLC to make (i) generally pro rata distributions to its unit holders, including us, in an amount at least sufficient to allow us to pay our taxes and to make payments under the Tax Receivable Agreement and any subsequent tax

34


 

receivable agreements that we may enter into in connection with future acquisitions and (ii) non-pro rata payments to us in an amount at least sufficient to reimburse us for our corporate and other overhead expenses. We are limited, however, in our ability to cause Ranger LLC and its subsidiaries to make these and other distributions or payments to us due to certain limitations, including restrictions under our Credit Facility and the cash requirements and financial condition of Ranger LLC. To the extent that we need funds and Ranger LLC or its subsidiaries are restricted from making such distributions or payments under applicable laws or regulations or under the terms of any future financing arrangements, or are otherwise unable to provide such funds, our liquidity and financial condition could be materially adversely affected.

 

Moreover, because we have no independent means of generating revenue, our ability to make payments under the Tax Receivable Agreement is dependent on the ability of Ranger LLC to make distributions to us in an amount sufficient to cover our obligations under the Tax Receivable Agreement. This ability, in turn, may depend on the ability of Ranger LLC's subsidiaries to make distributions to it. The ability of Ranger LLC, its subsidiaries and other entities in which it directly or indirectly holds an equity interest to make such distributions is subject to, among other things, (i) the applicable provisions of Delaware law (or other applicable jurisdiction) that may limit the amount of funds available for distribution and (ii) restrictions in relevant debt instruments entered into by Ranger LLC or its subsidiaries and/other entities in which it directly or indirectly holds an equity interest. To the extent that we are unable to make payments under the Tax Receivable Agreement for any reason, such payments will be deferred and will accrue interest until paid.

 

We are required to make payments under the Tax Receivable Agreement for certain tax benefits that we may claim, and the amounts of such payments could be significant.

 

Holders of Ranger Units (the “Ranger Unit Holders”) (other than Ranger) have the right to exchange their Ranger Units (and a corresponding number of shares of Class B Common Stock) for shares of our Class A Common Stock at an exchange ratio of one share of Class A Common Stock for each Ranger  Unit (and a corresponding number of shares of Class B Common Stock) exchanged (subject to conversion rate adjustments for stock splits, stock dividends and reclassifications), or, if either we or Ranger LLC so elects, cash.

 

We have entered into a Tax Receivable Agreement and certain members of Ranger Unitholders (each such person a “TRA Holder”). This agreement 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 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 after the Offering as a result of certain increases in tax basis and certain benefits attributable to imputed interest. We will retain the benefit of the remaining 15% of these cash savings. Payments we make under the Tax Receivable Agreement will be increased by any interest accrued from the due date (without extensions) of the corresponding tax return.

 

The term of the Tax Receivable Agreement commenced upon the completion of the Offering and will continue until all tax benefits that are subject to the Tax Receivable Agreement have been utilized or expired, unless we exercise our right to terminate the Tax Receivable Agreement (or the Tax Receivable Agreement is terminated due to other circumstances, including our breach of a material obligation thereunder or certain mergers, asset sales, other forms of business combination or other changes of control), and we make the termination payments specified in the Tax Receivable Agreement.

 

The payment obligations under the Tax Receivable Agreement are our obligations and not obligations of Ranger LLC, and we expect that the payments we will be required to make under the Tax Receivable Agreement will be substantial. Estimating the amount and timing of payments that may become due under the Tax Receivable Agreement is by its nature imprecise. For purposes of the Tax Receivable Agreement, cash savings in tax generally are calculated by comparing our actual tax liability (computed using the estimated impact of state and local taxes) to the amount we would have been required to pay had we not been able to utilize any of the tax benefits subject to the Tax Receivable Agreement. The actual increase in tax basis, as well as the amount and timing of any payments under the Tax Receivable Agreement, will vary depending upon a number of factors, including the timing of the redemptions of Ranger Units, the price of our Class A Common Stock at the time of each redemption, the extent to which such redemptions are taxable transactions, the amount of the redeeming Ranger Unit Holder's tax basis in its Ranger Units at the time of the relevant redemption, the depreciation and amortization periods that apply to the increase in tax basis, the amount, character and timing of the taxable income we generate in the future, the U.S. federal income tax rates then applicable, and the portion of our payments under the Tax Receivable Agreement that constitute imputed interest or give rise to depreciable or amortizable tax basis.

35


 

 

Our ability to realize the tax benefits that we currently expect to be available as a result of the increases in tax basis created by redemptions and our ability to utilize the interest deductions imputed under the Tax Receivable Agreement depends on a number of assumptions, including that we earn sufficient taxable income each year during the period over which such deductions are available and that there are no adverse changes in applicable law or regulations. If our actual taxable income was insufficient or there were adverse changes in applicable law or regulations, we may be unable to realize all or a portion of these expected benefits and our cash flows could be negatively affected.

 

In certain cases, payments under the Tax Receivable Agreement may be accelerated and/or significantly exceed the actual benefits, if any, we realize in respect of the tax attributes subject to the Tax Receivable Agreement.

 

If we experience a change of control (as defined under the Tax Receivable Agreement, which includes certain mergers, asset sales and other forms of business combinations) or the Tax Receivable Agreement terminates early (at our election or it is terminated early due to our breach of a material obligation thereunder) our obligations under the Tax Receivable Agreement would accelerate and we would be required to make a substantial immediate payment equal to the present value of the anticipated future payments to be made by us under the Tax Receivable Agreement (determined by applying a discount rate equal to one-year London Interbank Offered Rate ("LIBOR") plus 150 basis points). The calculation of hypothetical future payments will be based upon certain assumptions and deemed events set forth in the Tax Receivable Agreement, including (i) the assumption that we have sufficient taxable income to fully utilize the tax benefits covered by the Tax Receivable Agreement (including having sufficient taxable income to currently utilize any accumulated net operating loss carryforwards) and (ii) the assumption that any Ranger Units (other than those held by us) outstanding on the termination date are deemed to be redeemed on the termination date. Any early termination payment may be made significantly in advance of, and may materially exceed, the actual realization, if any, of the future tax benefits to which the termination payment relates.

 

As a result of either an early termination or a change of control, we could be required to make payments under the Tax Receivable Agreement that exceed our actual cash tax savings under the Tax Receivable Agreement. In these situations, our obligations under the Tax Receivable Agreement could have a substantial negative impact on our liquidity and could have the effect of delaying, deferring or preventing certain mergers, asset sales or other forms of business combinations or changes of control that could be in the best interests of holders of our Class A Common Stock.  For example, if the Tax Receivable Agreement were terminated at December 31, 2017 the present value of the estimated termination payments would, in the aggregate, be approximately $8.1 million (calculated using a discount rate equal to one-year LIBOR plus 150 basis points, applied against an undiscounted liability of approximately $8.6 million). The foregoing amount is merely an estimate and the actual payment could differ materially. There can be no assurance that we will be able to finance our obligations under the Tax Receivable Agreement.

 

In the event that our payment obligations under the Tax Receivable Agreement are accelerated upon certain mergers, other forms of business combinations or other changes of control, the consideration payable to holders of our Class A Common Stock could be substantially reduced.

 

If we experience a change of control (as defined under the Tax Receivable Agreement, which includes certain mergers, asset sales and other forms of business combinations), we would be obligated to make a substantial, immediate lump-sum payment, and such payment may be significantly in advance of, and may materially exceed, the actual realization, if any, of the future tax benefits to which the payment relates. As a result of this payment obligation, holders of our Class A Common Stock could receive substantially less consideration in connection with a change of control transaction than they would receive in the absence of such obligation. Further, our payment obligations under the Tax Receivable Agreement will not be conditioned upon the TRA Holders' having a continued interest in us or Ranger LLC. Accordingly, the TRA Holders' interests may conflict with those of the holders of our Class A Common Stock.  

 

We will not be reimbursed for any payments made under the Tax Receivable Agreement in the event that any tax benefits are subsequently disallowed.

 

Payments under the Tax Receivable Agreement will be based on the tax reporting positions that we will determine. The TRA Holders will not reimburse us for any payments previously made under the Tax Receivable Agreement if any tax benefits that have given rise to payments under the Tax Receivable Agreement are subsequently

36


 

disallowed, except that excess payments made to any TRA Holder will be netted against payments that would otherwise be made to such TRA Holder, if any, after our determination of such excess. As a result, in such circumstances, we could make payments that are greater than our actual cash tax savings, if any, and may not be able to recoup those payments, which could adversely affect our liquidity.

 

In certain circumstances, Ranger LLC will be required to make tax distributions to the Ranger Unit Holders, including us, and the tax distributions that Ranger LLC will be required to make may be substantial. To the extent we receive tax distributions in excess of our tax liabilities and obligations to make payments under the Tax Receivable Agreement and do not distribute such cash balances as dividends on our Class A Common Stock, the Ranger Unit Holders (other than us) would benefit from such accumulated cash balances if they exercise their Redemption Right.

 

Ranger LLC is treated as a partnership for U.S. federal income tax purposes and, as such, is not subject to U.S. federal income tax. Instead, taxable income will be allocated to the Ranger Unit Holders, including us. Pursuant to the Ranger LLC Agreement, Ranger LLC will make generally pro rata cash distributions, or tax distributions, to the Ranger Unit Holders, including us, calculated using an assumed tax rate, to allow each of the Ranger Unit Holders to pay its respective taxes on such holder's allocable share of Ranger LLC's taxable income; such tax distributions will be calculated after taking into account certain other distributions or payments received by the Ranger Unit Holders from Ranger LLC or Ranger Inc. Under applicable tax rules, Ranger LLC is required to allocate taxable income disproportionately to its members in certain circumstances. Because tax distributions will be determined based on the Ranger Unit Holder that is allocated the largest amount of taxable income on a per unit basis and on an assumed tax rate that is the highest possible rate applicable to any Ranger Unit Holder, but will be made pro rata based on ownership, Ranger LLC will be required to make tax distributions that, in the aggregate, will likely exceed the amount of taxes that Ranger LLC would have paid if it were taxed on its net income at the assumed rate. The pro rata distribution amounts will also be increased to the extent necessary, if any, to ensure that the amount distributed to Ranger Inc. is sufficient to enable Ranger Inc. to pay its actual tax liabilities and amounts payable under the Tax Receivable Agreement (other than accelerated amounts payable under the Tax Receivable Agreement as a result of a change of control or termination event, which we expect to be subject to restrictions contained in our Credit Facility).

 

Funds used by Ranger LLC to satisfy its tax distribution obligations will not be available for reinvestment in our business. Moreover, the tax distributions Ranger LLC will be required to make may be substantial, and may exceed (as a percentage of Ranger LLC's income) the overall effective tax rate applicable to a similarly situated corporate taxpayer. In addition, because these payments will be calculated with reference to an assumed tax rate, and because of the disproportionate allocation of taxable income, these payments will likely significantly exceed the actual tax liability for many of the Ranger Unit Holders.

 

As a result of potential differences in the amount of taxable income allocable to us and to the other Ranger Unit Holders, as well as the use of an assumed tax rate in calculating Ranger LLC's tax distribution obligations, we may receive distributions significantly in excess of our tax liabilities and obligations to make payments under the Tax Receivable Agreement. If we do not distribute such cash balances as dividends on our Class A Common Stock and instead, for example, hold such cash balances or lend them to Ranger LLC, the Ranger Unit Holders (other than us) would benefit from any value attributable to such accumulated cash balances as a result of their ownership of Class A Common Stock following a redemption of their Ranger Units pursuant to the Redemption Right or their receipt of an equivalent amount of cash.

 

If Ranger LLC were to become a publicly traded partnership taxable as a corporation for U.S. federal income tax purposes, we and Ranger LLC might be subject to potentially significant tax inefficiencies, and we would not be able to recover payments previously made by us under the Tax Receivable Agreement even if the corresponding tax benefits were subsequently determined to have been unavailable due to such status.

 

We intend to continue to operate such that Ranger LLC does not become a publicly traded partnership taxable as a corporation for U.S. federal income tax purposes. A "publicly traded partnership" is a partnership, the interests of which are traded on an established securities market or are readily tradable on a secondary market or the substantial equivalent thereof. Under certain circumstances, redemptions of Ranger Units pursuant to a Redemption Right (or our Call Right) or other transfers of Ranger Units could cause Ranger LLC to be treated as a publicly traded partnership. Applicable U.S. Treasury regulations provide for certain safe harbors from treatment as a publicly traded partnership,

37


 

and we intend to continue to operate such that redemptions or other transfers of Ranger Units qualify for one or more such safe harbors. For example, we intend to continue to limit the number of Ranger Unit Holders, and the Ranger LLC Agreement provides for limitations on the ability of Ranger Unit Holders to transfer their Ranger Units and provides us, as managing member of Ranger LLC, with the right to impose restrictions (in addition to those already in place) on the ability of Ranger Unit Holders to redeem their Ranger Units pursuant to a Redemption Right to the extent we believe it is necessary to ensure that Ranger LLC will continue to be treated as a partnership for U.S. federal income tax purposes.

 

If Ranger LLC were to become a publicly traded partnership, significant tax inefficiencies might result for us and for Ranger LLC, including as a result of our inability to file a consolidated U.S. federal income tax return with Ranger LLC. In addition, we may not be able to realize tax benefits covered under the Tax Receivable Agreement, and we would not be able to recover any payments previously made by us under the Tax Receivable Agreement, even if the corresponding tax benefits (including any claimed increase in the tax basis of Ranger LLC's assets) were subsequently determined to have been unavailable.

 

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 2. PROPERTIES

Properties and Equipment

Properties

Our principal executive offices are located at 800 Gessner Street, Suite 1000, Houston, Texas 77024 and our telephone number is 713-935-8900. We lease our 29,000 square foot general office space at our corporate headquarters. The lease expires in 2020. We currently own or lease the following additional principal properties:

 

 

 

 

 

 

Facility Location

Purpose

Size (sq ft/acres)

Leased
or
Owned

Lease
Expiration

Segment

Bowie, Texas

Maintenance Facility/Yard/Field Office

23,584 sq ft/ 8 acres

Leased

2020

Well Services

Bowie, Texas

Maintenance Facility/Yard/Field Office

3,100 sq ft/ 1 acre

Leased

2020

Well Services

Dickinson, North Dakota

Maintenance Facility/Yard/Field Office

11,120 sq ft/3.5 acres

Owned

N/A

Well Services

Gillette, Wyoming

Maintenance Facility/Yard/Field Office

42,500 sq ft/30 acres

Leased

2018

Well Services

Milliken, Colorado

Maintenance Facility/Yard/Field Office

124,000 sq ft/23 acres

Owned

N/A

Well Services

Monahan, Texas

Maintenance Facility/Yard

6,400 sq ft/ 10 acres

Leased

2020

Well Services

Newtown, North Dakota

Maintenance Facility/Yard/Field Office

10,000 sq ft/3.5 acres

Owned

N/A

Well Services

Odessa, Texas

Maintenance Facility/Yard/Field Office

5,000 sq ft/5 acres

Leased

2020

Well Services

Pleasanton, Texas

Maintenance Facility/Yard/Field Office

7,800 sq ft/3 acres

Owned

N/A

Well Services

38


 

 

 

 

 

 

 

Facility Location

Purpose

Size (sq ft/acres)

Leased
or
Owned

Lease
Expiration

Segment

San Angelo, Texas

Maintenance Facility/Yard/Field Office

12,055 sq ft/ 10 acres

Leased

2020

Well Services

Wharton, Texas

Field Office/Yard

2,000 sq ft/4 acres

Leased

2018

Well Services

Williston, North Dakota

Maintenance Facility/Yard/Field Office

10,820 sq ft/4.5 acres

Leased

2018

Well Services

Farmington, New Mexico

Maintenance Facility/Field Office

5,000 sq ft/3.0 acres

Leased

2018

Well Services

Palestine, Texas

Maintenance Facility/Yard/Field Office

2,000 sq ft/3.0 acres

Leased

2020

Well Services

Hobbs, New Mexico

Yard

6.0 acres

Leased

2019

Well Services

Hobbs, New Mexico

Maintenance Facility/Yard/Field Office

7,500 sq ft/3.4 acre

Leased

2020

Well Services

Calumet, Oklahoma

Maintenance Facility/Yard/Field Office

7310 sq ft/3 acres

Leased

2020

Well Services

Midland, TX

Maintenance Facility/Yard/Field Office

36,231 sq ft/12 acres

Leased

2027

Well Services

 

We also lease several smaller facilities, which leases generally have shorter term. We believe that our facilities are adequate for our operations and their locations allow us to efficiently serve our customers. We do not believe that any single facility is material to our operations and, if necessary, we could readily obtain a replacement facility.

Equipment

Well Services

We have 135 well service rigs in our fleet, 134 of which are considered to be “high‑spec,” with high operating HP (450 HP or greater) and tall mast heights (102 feet or higher). The only rig in our fleet that is not high‑spec is generally deployed only for plugging and abandonment operations on conventional vertical wells. We also have eight older plugging and abandonment rigs that we no longer market as part of our well service rig fleet. In February 2017, we entered into the NOV Purchase Agreement, pursuant to which we accepted delivery of 16 high-spec rigs in 2017 and expect to accept delivery of an additional 9 high‑spec well service rigs in 2018. As a result of the NOV Purchase Agreement, our well service rig fleet will expand to 144 rigs, 143 of which will be considered to be high‑spec.

The high‑spec well service rigs in our fleet, the substantial majority of which has been built since 2010, have an average age of approximately six years and feature modern operating components sourced from leading U.S. manufacturers. Approximately 62% of our existing high‑spec well service rigs were manufactured by NOV, with the remaining manufactured by Dragon/Cooper, Service King, Rig Works, Taylor and Stewart & Stevenson Crown.

 In connection with the operations of our high‑spec well service rigs, we also maintain a supply of additional service and rental equipment, including accumulators, acid and frac tanks, motor vehicles, trailers, tractors, catwalks, cementing units, snubbing units, pipe racks, power swivels, ram block assemblies, rig pumps and related items.

Processing Solutions

We have a fleet of more than 25 MRUs that are modern, reliable and equipped to handle large volumes of natural gas while operating across a broad array of oilfield conditions with minimal downtime and maintenance. Our MRUs are constructed and assembled by third‑party vendors in accordance with our proprietary designs and with our oversight of sourcing and procurement. Our MRUs can be stacked and scaled to handle a broad range of projects and natural gas volumes (i.e., 10, 20, 30, 40, 50 MMscfd and beyond). Our MRUs can generate temperatures down to −20

39


 

degrees Fahrenheit. In addition, we own and operate five (5) auxiliary NGL stabilizer units (designed to assist our MRUs that require additional capacity to separate and capture valuable NGLs), over 40 NGL storage tanks with bulkhead delivery systems and capacities of 18,000 gallons, fourteen trailer‑mounted natural gas generators and additional supporting auxiliary equipment. Our proprietary natural gas and NGL processing equipment is generally designed to be mobile and purpose‑built to increase efficiency and productivity while reducing safety risks.

ITEM 3. LEGAL PROCEEDINGS

Our operations are subject to a variety of risks and disputes normally incident to our business. As a result, we may, at any given time, be a defendant in various legal proceedings and litigation arising in the ordinary course of business. We are not currently a party to any legal proceedings that, if determined adversely against us, individually or in the aggregate, would have a material adverse effect on our business, liquidity position, financial condition, prospects or results of operations. We are, however, named defendants in certain lawsuits, investigations and claims arising in the ordinary course of conducting our business, including certain environmental claims and employee‑related matters, and we expect that we will be named defendants in similar lawsuits, investigations and claims in the future. We maintain insurance policies with insurers in amounts and with coverage and deductibles that we, with the advice of our insurance advisers and brokers, believe are reasonable and prudent. We cannot, however, assure you that this insurance will be adequate to protect us from all material expenses related to potential future claims for personal injury and property damage or that these levels of insurance will be available in the future at economical prices. While the outcome of these lawsuits, investigations and claims cannot be predicted with certainty, we do not expect these matters to have a material adverse impact on our business, results of operations, cash flows or financial condition.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

40


 

PART II

 

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Market Information

Our Class A Common Stock is listed on the NYSE under the symbol “RNGR.” There is no public market for our Class B Common Stock. The following table sets for the high and low sales prices of the Class A Common Stock during each subsequent quarter following our initial public offering on August 16, 2017.

 

 

 

 

 

 

 

 

 

High

 

Low

Quarter Ended

 

 

 

 

 

 

September 30, 2017 (1)

 

$

15.70

 

$

13.50

December 31, 2017

 

$

15.05

 

$

8.48

(1)

Our Class A Common Stock began trading on the NYSE on August 11, 2017 in connection with the Offering.

Dividend Policy

We have not paid any dividends since our inception and we do not anticipate declaring or paying any cash dividends to holders of our Class A Common Stock in the foreseeable future. We currently intend to retain future earnings, if any, to finance the growth of our business.

Holders

On March 1, 2018,  the last reported sales price of our common stock on the NYSE was $8.63. As of February 15, 2018, there were five shareholders of record of our Class A Common Stock and four shareholders of record of our Class B Common Stock. This number does not include shareholders whose shares are held for them in “street name” meaning that such shareholders are held for their accounts by a broker or other nominee. The actual number of beneficial shareholders is greater than the number of holders of record. 

Stock Performance Graph

The following graph compares the cumulative total return to shareholders on our Class A Common Stock, the NYSE Composite Index and an industry peer group (“Peer Group”). The Peer Group consists of Basic Energy Services, Inc.; Key Energy Services, Inc.; Superior Energy Services, Inc.; C&J Energy Services, Inc. and Pioneer Energy Services Corp. The graph assumes that $100.00 was invested in our common shares on August 10, 2017, the initial trading day for our common stock and ended on December 31, 2017. We have not declared any dividends during the periods covered by this graph. 

41


 

Picture 2

The graph and related information should not be deemed “soliciting material” or to be “filed” with the SEC, nor should such information be incorporated by reference into any future filing under the Securities Act or the Exchange Act, except to the extent that we specifically incorporate such information by reference into such a filing. The graph and information is included for historical comparative purposes only and should not be considered indicative of future stock performance.

Recent Sales of Unregistered Equity Securities

We had no sales of unregistered equity securities during the period covered by this Annual Report that were not previously reported in a Current Report on Form 8-K or Quarterly Report on Form 10-Q.

Use of Proceeds from Registered Securities

On August 16, 2017, Ranger completed the Offering of 5,862,069 shares of its Class A Common Stock pursuant to our registration statement on Form S-1 (File No. 333-218139) declared effective by the SEC on August 10, 2017. Credit Suisse Securities (USA) LLC, Piper Jaffray & Co. and Wells Fargo Securities, LLC acted as representatives of the underwriters and Barcalys Capital Inc., Evercore Group L.L.C., Capital One Securities, Inc., Johnson Rice & Company L.L.C., Raymond James & Associates, Inc. and Scotia Capital (USA) Inc. acted as joint book-running managers in the Offering. 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 Ranger of $80.8 million, after deducting $4.2 million of underwriting discounts and commissions. Ranger received net proceeds of approximately $20.7 million after the Company paid off the remainder of our long term debt of $10.4 million, funded $45.2 million for the cash portion of the ESCO Acquisition, $3.9 million of costs incurred due to the Offering, and $0.7 million for cash bonuses to certain employees. The remaining net proceeds were used to fund capital expenditures and general business expenses. No fees or expenses were paid, directly or indirectly, to any officer, director or 10% unitholder or other affiliate.

Issuer Purchase of Equity Securities

None.

42


 

ITEM 6. Selected Financial Data

The historical financial statements included in this Annual Report reflect the consolidated results of operations of the Company, and for periods prior to August 16, 2017, the consolidated financial statements of the Predecessor. Ranger Energy Services, LLC (“Ranger Services”) was, through Ranger Energy Holdings, LLC (“Ranger Holdings”), formed by CSL Capital Management, LLC (“CSL”) in June 2014. Torrent Energy Services, LLC (“Torrent Services”) was, through Torrent Energy Holdings, LLC (“Torrent Holdings”), acquired by CSL in September 2014. Ranger Services and Torrent Services collectively referred to herein as the “Predecessor”. In connection with the consummation of the Offering, the Predecessor became a controlled subsidiary of the Company.

The following table shows selected historical financial and operating data of the Company and the Predecessor for the periods and as of the dates indicated.

We derived the information in the following table from, and that information should be read together with, and is qualified in its entirety by reference to, the audited consolidated financial statements and the accompanying notes included elsewhere in this Annual Report.  A discussion of our critical accounting estimates is included in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7 of this Annual Report.

 

 

 

 

 

 

 

 

 

 

 

    

December 31, 

    

December 31, 

    

December 31, 

 

 

2017

 

2016

 

2015

 

 

(in millions, except per share and hourly amounts)

Statement of operations data:

 

 

 

 

 

 

 

 

 

Revenues

 

$

154.0

 

$

52.8

 

$

21.2

Operating loss

 

$

(20.6)

 

$

(4.5)

 

$

(6.4)

Net loss

 

$

(27.3)

 

$

(5.0)

 

$

(6.7)

Net loss attributable to Ranger Energy Services, Inc.

 

$

(6.6)

 

$

 -

 

$

 -

Net loss per share - basic

 

$

(0.78)

 

$

 -

 

$

 -

Net loss per share - diluted

 

$

(0.78)

 

$

 -

 

$

 -

Balance sheet data (as of December 31, 2017 and 2016)

 

 

 

Working Capital

 

$

(3.2)

 

$

10.4

 

 

 

Property, plant and equipment, net

 

$

189.2

 

$

102.4

 

 

 

Total assets

 

$

259.7

 

$

135.7

 

 

 

Long-term debt

 

$

7.3

 

$

10.1

 

 

 

Shareholders' equity / net parent investment

 

$

195.7

 

$

112.6

 

 

 

Other

 

 

 

 

 

 

 

 

 

Net cash used in operating activities

 

$

(17.3)

 

$

(5.2)

 

$

(5.2)

Net cash used in investing activities

 

$

(68.9)

 

$

(25.4)

 

$

(25.5)

Net cash provided by financing activities

 

$

89.9

 

$

31.1

 

$

28.9

Capital Expenditures

 

$

56.9

 

$

12.2

 

$

26.8

Adjusted EBITDA (1)

 

$

11.2

 

$

3.1

 

$

(2.6)

Rig Hours

 

 

211,200

 

 

58,800

 

 

22,800

Average Monthly Hours per rig

 

 

194

 

 

178

 

 

188

 

(1)

For a discussion of the non-GAAP financial measure Adjusted EBITDA, including a reconciliation of Adjusted EBITDA to its most directly comparable financial measure calculated and presented in accordance with GAAP, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and specifically “Non-GAAP Financial Measures” in Item 7 of this Annual Report.

43


 

ITEM 7. 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 elsewhere in this Annual 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 “Item 1A.-Risk Factors” included elsewhere in this report. We assume no obligation to update any of these forward‑looking statements, except as required by applicable law.

Overview

We are 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 135 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 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, 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, the Gulf Coast and the SCOOP and STACK plays.

Our Predecessor and Ranger Energy Services, Inc.

We were 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 consolidated basis. In connection with the transactions described in Note 1 – Organization and Business Operations – Reorganization, 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 consolidated financial information included in this Annual 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 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 consolidated related notes thereto included elsewhere in this Annual Report.

On August 16, 2017, the Company acquired 49 high-spec well service rigs, certain ancillary equipment, and certain liabilities of ESCO. ESCO is included in our consolidated financial results from the date of acquisition onward.

44


 

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 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 19 - Segment Reporting to the 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 of $80.8 million, after deducting $4.2 million of underwriting discounts and commissions. We received net proceeds of approximately $20.7 million after the we paid off the remainder of our long term debt of $10.4 million, funded $45.2 million for the cash portion of the ESCO Acquisition, $3.9 million of costs incurred due to the Offering, and $0.7 million for cash bonuses to certain employees. The remaining 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.

We recognize revenue in our Well Services segment when services are performed, collection of the relevant receivables is probable, persuasive evidence of an arrangement exists and the price is fixed or determinable. We price well servicing by the hour or by the day when services are performed. Well servicing is sold without warranty or right of return.

We recognize revenue in our Processing Solutions segment when services are performed, collection of the relevant receivables is probable, persuasive evidence of an arrangement exists and the price is fixed or determinable. Revenues from equipment leasing, operations and maintenance services are recognized as earned. These services are sold without warranty or right of return.

Costs of Conducting Our Business

The principal expenses involved in conducting our business are personnel, repairs and maintenance costs, general and administrative costs, 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,

45


 

which improves safety rates and reduces attrition. We also incur costs to employ personnel to support and manage 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 intends to use 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

·

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 loss before interest expense, net, income tax provision (benefit), depreciation and amortization, equity‑based compensation, acquisition‑related and severance costs, impairment of goodwill and other non‑cash and certain other items that we do not view as indicative of our ongoing performance. See “—Results of Operations—Note Regarding Non‑GAAP Financial Measure” for more information and reconciliations of net income (loss) to Adjusted EBITDA, the most directly comparable financial measure calculated and presented in accordance with GAAP.

Rig Hours

Within our Well 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.

46


 

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 is added to our fleet during a month, meaning that we have taken delivery of such well service rig and is ready for service, is 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. For example, our competitors’ well service rig fleets are typically comprised primarily of older, lower spec well service rigs that are not as well suited to servicing modern horizontal well designs as are high-spec well service rigs, which may result in lower average rig hours per rig for our competitors’ fleets as compared to our fleet.

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 excess, rig availability to meet such demand.

For the years ending December 31, 2017, 2016 and 2015, our rig utilization as measured by average monthly hours per rig was approximately 194, 178 and 188, respectively. Actual aggregate operating well service rig hours for the years ending December 31, 2017, 2016 and 2015 were 211,200, 58,800, and 22,800. The increase in the rig hours is primarily as a result of our acquisitions of ESCO, Magna, Bayou, and their associated well service rigs as well as newly acquired service rigs. The related increase in rig utilization resulted from an increase in the average number of well service rigs in our active fleet from 18 in 2015 to 30 in 2016 to 91 in 2017, and a corresponding increase in our potential aggregate well service rig hours.

Factors Impacting the Comparability of Results of Operations

Magna and Bayou Acquisitions

Our Predecessor’s historical consolidated financial statements for the years ended December 31, 2017, 2016 and 2015 include the results of operations for Magna and Bayou from their respective acquisition dates during 2016. As a result, our Predecessor’s historical financial data does not give an accurate indication of what our actual results would have been if such acquisitions had been completed at the beginning of the periods presented or of what our future results of operations are likely to be.

ESCO Acquisition

Our Predecessor’s historical consolidated financial statements for the years ended December 31, 2017, 2016 and 2015 do not include the results of operations for the assets we acquired in the ESCO Acquisition, other than for the period from August 16, 2017 to December 31, 2017. As a result, our Predecessor’s historical financial data do 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.

Public Company Costs

We incurred incremental, non‑recurring costs related to our transition to a publicly traded and taxable corporation, including the costs of the Offering. We are incurring and will continue to incur costs associated with the initial implementation of our Sarbanes‑Oxley Section 404 internal control implementation. We also are incurring and

47


 

expect to continue to incur additional significant and recurring expenses as a publicly traded corporation, including costs associated with the employment of additional personnel, compliance under the Exchange Act, and Annual Reports to common shareholders, registrar and transfer agent fees, national stock exchange fees, audit fees, Sarbanes-Oxley Section 404 internal testing, incremental director and officer liability insurance costs and director and officer compensation.

Reorganization

We were incorporated to serve as the issuer in the Offering and have no previous operations, assets or liabilities. Ranger Services and Torrent Services were contributed to us in connection with the Offering and the transactions described under “Organization” in Item 1 of this Annual Report and thereby became our subsidiaries. As we integrate our operations and further implement controls, processes and infrastructure, it is likely that we will incur incremental selling, general and administrative expenses relative to historical periods.

 In addition, we entered into a Tax Receivable Agreement with the TRA Holders. This agreement generally provides for the payment by us to a TRA Holder of 85% of the net cash savings, if any, in U.S. federal, state and local income tax or franchise tax that we actually realize (or are deemed to realize in certain circumstances) in periods after the Offering as a result of (i) any tax basis increases resulting from the contribution in connection with the Offering by such TRA Holder of all or a portion of its Ranger Units to us in exchange for shares of Class A Common Stock, (ii) the tax basis increases resulting from the redemption by such TRA Holder of Ranger Units for shares of Class A Common Stock pursuant to the Redemption Right or our Call Right and (iii) imputed interest deemed to be paid by us as a result of, and additional tax basis arising from, any payments we make under the Tax Receivable Agreement. We will retain the benefit of the remaining 15% of these cash savings. See “Certain Relationships and Related Party Transactions—Tax Receivable Agreement.”

 Income Taxes

We are a Subchapter C corporation under the Internal Revenue Code of 1986, as amended (the “Code”), and, as a result, are subject to U.S. federal, state and local income taxes. Although the Predecessor Companies were subject to franchise tax in the State of Texas (at less than 1% of modified pre‑tax earnings), they have historically passed through their taxable income to their owners for U.S. federal and other state and local income tax purposes and thus were not subject to U.S. federal income taxes or other state or local income taxes. Accordingly, the financial data attributable to our Predecessor contains no provision for U.S. federal income taxes or income taxes in any state or locality other than franchise tax in the State of Texas. We account for income taxes under the asset and liability method. Under this method, deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates in effect for the year in which those temporary differences are expected to be recovered or settled pursuant to the provisions of Accounting Standards Codification (“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.

Internal Controls and Procedures

We and our independent auditors identified a material weakness in our internal control over financial reporting as of December 31, 2017 in addition to the previously disclosed material weakness for the year ended December 31, 2016. A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting such that there is a reasonable possibility that a material misstatement of our annual or interim financial statements will not be prevented or detected on a timely basis. The material weaknesses each related to the lack of sufficient qualified accounting personnel, which led to the incorrect application of generally accepted accounting principles, ineffective controls over accounting for non-routine and/or complex transactions, and ineffective controls over the financial statement close and reporting processes.

We are evaluating our controls over accounting for non-routine and/or complex transactions in an effort to identify additional controls to timely identify misstatements and strengthen our overall control environment as well as continuing to assess our qualified accounting personnel staffing requirements.  We can give no assurance that these actions will remediate this deficiency in internal control or that additional material weaknesses or significant deficiencies

48


 

in our internal control over financial reporting will not be identified in the future. Our failure to implement and maintain effective internal control over financial reporting could result in errors in our financial statements that could result in a restatement of our financial statements and cause us to fail to meet our reporting obligations.

We hired additional finance and accounting personnel and continue to evaluate all of our personnel in all key finance and accounting positions.

We are required to comply with the SEC's rules implementing Section 302 of Sarbanes-Oxley, which requires our management to certify financial and other information in our quarterly and Annual Reports. However, this Annual Report does not include a report of management’s assessment regarding internal control over financial reporting or an attestation report of our independent registered public accounting firm due to a transition period established by SEC rules applicable to newly public companies. We will be required to provide an annual management report on the effectiveness of our internal control over financial reporting beginning with our Annual Report for the year ended December 31, 2018. We will not be required to have our independent registered public accounting firm attest to the effectiveness of our internal control over financial reporting under Section 404 until our first Annual Report subsequent to our ceasing to be an "emerging growth company" within the meaning of Section 2(a)(19) of the Securities Act.

Results of Operations

The Year Ended December 31,  2017 compared to The Year Ended December 31,  2016

The following table sets forth our results of operations for the year ended December 31, 2017 as compared to the year ended December 31, 2016. 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

December 31, 

 

Change

 

 

    

2017

    

2016

    

$

    

%

 

Revenues:

 

 

  

 

 

  

 

 

 

  

  

 

Well Services

 

$

145.7

 

$

46.3

 

$

99.4

 

215

%

Processing Solutions

 

 

8.3

 

 

6.5

 

 

1.8

 

28

 

Total revenues

 

 

154.0

 

 

52.8

 

 

101.2

 

192

 

Operating expenses:

 

 

  

 

 

  

 

 

  

 

  

 

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

 

 

  

 

 

  

 

 

  

 

  

 

Well Services

 

 

123.2

 

 

36.7

 

 

86.5

 

236

 

Processing Solutions

 

 

3.2

 

 

2.6

 

 

0.6

 

23

 

Total cost of services

 

 

126.4

 

 

39.3

 

 

87.1

 

222

 

General and administrative

 

 

30.4

 

 

11.4

 

 

19.0

 

167

 

Depreciation and amortization

 

 

17.8

 

 

6.6

 

 

11.2

 

170

 

Total operating expenses

 

 

174.6

 

 

57.3

 

 

117.3

 

205

 

Operating loss

 

 

(20.6)

 

 

(4.5)

 

 

(16.1)

 

358

 

Other expenses

 

 

  

 

 

  

 

 

  

 

  

 

Interest expense, net

 

 

(6.3)

 

 

(0.5)

 

 

(5.8)

 

1,160

 

Total other expenses

 

 

(6.3)

 

 

(0.5)

 

 

(5.8)

 

1,160

 

Loss before income tax expense

 

 

(26.9)

 

 

(5.0)

 

 

(21.9)

 

438

 

Tax expense

 

 

(0.4)

 

 

 —

 

 

(0.4)

 

 —

 

Net loss

 

$

(27.3)

 

$

(5.0)

 

$

(22.3)

 

446

%

 

Revenues. Revenues for the year ended December 31, 2017 increased $101.2 million, or 192%, to $154.0 million from $52.8 million for the year ended December 31, 2016. The increase in revenues by segment was as follows:

Well Services. Well Services revenues for the year ended December 31, 2017 increased $99.4 million, or 215%, to $145.7 million from $46.3 million for the year ended December 31, 2016. The increase was primarily due to an increased number of rigs, to an average of 91 rigs from an average of 31 rigs, providing workover rig services, which accounted for $67.6 million. Approximately $11.9 million of the increase in workover rig services was due to the ESCO Acquisition. The increase in workover rig services included a 213% increase in total rig hours to 184,000 from 58,800

49


 

for the year ended December 31, 2017 compared to the year ended December 31, 2016. The increase was principally due to a full year of activity of the acquired rigs and the related services and equipment.

Processing Solutions. Processing Solutions revenues for the year ended December 31, 2017 increased $1.8 million, or 28%, to $8.3 million from $6.5 million for the year ended December 31, 2016. The increase was primarily attributable to an increase in MRU revenue due to an additional 4 units, increased MRU utilization and an increase in our rental rates.

Cost of services (excluding depreciation and amortization shown separately). Cost of services for the year ended December 31, 2017 increased $87.1 million, or 222%, to $126.4 million from $39.3 million for the year ended December 31, 2016. As a percentage of revenue, cost of services was 82% and 75% for the years ended December 31, 2017 and 2016, respectively. The increase in cost of services by segment was as follows:

Well Services. Well Services cost of services for the year ended December 31, 2017 increased $86.5 million, or 236%, to $123.2 million from $36.7 million for the year ended December 31, 2016. 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 year ended December 31, 2017 increased $0.6 million, or 23%, to $3.2 million from $2.6 million for the year ended December 31, 2016. The increase was primarily attributable to increases in mobilization and installation costs incurred which corresponds with additional revenues.

General & Administrative. General and administrative expenses for the year ended December 31, 2017 increased $19.0 million, or 167%, to $30.4 million from $11.4 million for the year ended December 31, 2016. The increase in general and administrative expenses by segment was as follows:

Well Services and Other.  Well Services and Other general and administrative expenses for the year ended December 31, 2017 increased $19.5 million, or 244%, to $27.5 million from $8.0 million for the year ended December 31, 2016. The increase was primarily attributable to an increase in expenses due to the expansion of the Company’s activities; notably costs associated with the Offering, expenses for payroll costs (including severance costs), professional, office costs, and equity‑based compensation expense. Included in the $27.5 million of general and administrative expenses is $10.7 million that is included in other.

Processing Solutions. Processing Solutions general and administrative expenses for the year ended December 31, 2017 decreased $0.5 million, or 15%, to $2.9 million from $3.4 million for the year ended December 31, 2016 primarily due to a reduction in payroll and administrative costs.  

Depreciation and Amortization. Depreciation and amortization for the year ended December 31, 2017 increased $11.2 million, or 170%, to $17.8 million from $6.6 million for the year ended December 31, 2016. The increase in depreciation and amortization expense by segment was as follows:

Well Services and Other.  Well Services and Other depreciation and amortization expense for the year ended December 31, 2017 increased $10.9 million, or 195%, to $16.5 million from $5.6 million for the year ended December 31, 2016. The increase was primarily attributable to fixed assets that were put in place during 2016 and the year ended December 31, 2017, due to the acquisitions of ESCO, Magna, and Bayou as well as additional fixed asset purchases. Included in the $16.5 million of depreciation and amortization expenses is $0.3 million that is included in other.

Processing Solutions. Processing Solutions depreciation and amortization expense was $1.3 million for the year ended December 31, 2017 compared to $1.0 million for the year ended December 31, 2016, primarily due to the additional assets during 2017.

50


 

Interest Expense, net. Interest expense, net for the year ended December 31, 2017 increased $5.8 million, or 1,160%, to $6.3 million from $0.5 million for the year ended December 31, 2016. The increase to interest expense, net by segment was as follows:

Well Services and Other.  Well Services and Other interest expense, net for the year ended December 31, 2017 increased $5.8 million, or 14,500%, to $6.2 million from $0.4 million for the year ended December 31, 2016. The increase to interest expense, net was attributable to an increase in average borrowing as well as the payment of the make‑whole in connection with repaying and retiring the related party loans during the year ended December 31, 2017,  of $5.2 million, compared to the year ended December 31, 2016. Included in the $6.2 million of interest expenses is $5.2 million that is included in other.

Processing Solutions. Processing Solutions interest expense, net was less than $0.1 million for the years ended December 31, 2017 and 2016.

The Year Ended December 31,  2016 compared to The Year Ended December 31,  2015

The following table sets forth our results of operations for the year ended December 31, 2016 as compared to the year ended December 31, 2015.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Year Ended

 

 

 

 

 

 

 

 

December 31, 

 

Change

 

 

    

2016

    

2015

    

$

    

%

 

Revenues:

 

 

  

 

 

  

 

 

  

  

 

 

Well Services

 

$

46.3

 

$

9.7

 

$

36.6

 

377

%

Processing Solutions

 

 

6.5

 

 

11.5

 

 

(5.0)

 

(43)

 

Total revenues

 

 

52.8

 

 

21.2

 

 

31.6

 

149

 

Operating expenses:

 

 

  

 

 

  

 

 

  

 

  

 

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

 

 

  

 

 

  

 

 

  

 

  

 

Well Services

 

 

36.7

 

 

8.2

 

 

28.5

 

348

 

Processing Solutions

 

 

2.6

 

 

7.9

 

 

(5.3)

 

(67)

 

Total cost of services

 

 

39.3

 

 

16.1

 

 

23.2

 

144

 

General and administrative

 

 

11.4

 

 

7.8

 

 

3.6

 

46

 

Depreciation and amortization

 

 

6.6

 

 

2.1

 

 

4.5

 

214

 

Impairment of goodwill

 

 

 —

 

 

1.6

 

 

(1.6)

 

(100)

 

Total operating expenses

 

 

57.3

 

 

27.6

 

 

29.7

 

108

 

Operating loss

 

 

(4.5)

 

 

(6.4)

 

 

1.9

 

30

 

Other expenses

 

 

  

 

 

  

 

 

  

 

  

 

Interest expense, net

 

 

(0.5)

 

 

(0.3)

 

 

(0.2)

 

(67)

 

Total other expenses

 

 

(0.5)

 

 

(0.3)

 

 

(0.2)

 

(67)

 

Loss before income tax expense

 

 

(5.0)

 

 

(6.7)

 

 

1.7

 

25

 

Tax expense

 

 

 —

 

 

 —

 

 

 —

 

 —

 

Net loss

 

$

(5.0)

 

$

(6.7)

 

$

1.7

 

25

%

 

Revenues. Revenues for 2016 increased $31.6 million, or 149%, to $52.8 million from $21.2 million for 2015. The increase in revenues by segment was as follows:

Well Services. Well Services revenues for 2016 increased $36.6 million, or 377%, to $46.3 million from $9.7 million for 2015. Magna and Bayou represented $30.6 million of the increase. The remaining $6.0 million increase was attributable to legacy Ranger, primarily due to increased demand in our workover rig services, which accounted for $4.4 million, or 73% of the remaining segment increase. The $4.4 million increase in workover rig services included a $5.5 million increase due to a 62% increase in total rig hours for 2016 compared to 2015, offset by a reduction of $1.1 million due to an 8% decrease in the average rig rates for 2016 compared to 2015.

Processing Solutions. Processing Solutions revenues for 2016 decreased $5.0 million, or 43%, to $6.5 million from $11.5 million for 2015. The decrease was primarily attributable to a strategic shift by the business to significantly

51


 

decrease the amount of mobilization and demobilization services and a decrease in the compressor rental services as a result of basin revenue mix changes. The mobilization and demobilization and compressor rental services accounted for $0.7 million and $5.6 million for 2016 and 2015, respectively, or 97% of the change in revenue from 2015 to 2016. The strategic shift was in large part due to a change in business focus from the Bakken Basin to the Permian Basin where customers typically rent compressors directly from compressor rental houses.

Cost of services (excluding depreciation and amortization shown separately). Cost of services for 2016 increased $23.2 million, or 144%, to $39.3 million from $16.1 million for 2015. As a percentage of revenue, cost of services was 74% and 76% for 2016 and 2015, respectively. The increase in cost of services by segment was as follows:

Well Services. Well Services cost of services for 2016 increased $28.5 million, or 348%, to $36.7 million from $8.2 million for 2015. Magna and Bayou represented $24.1 million of the increase. The remaining $4.4 million increase was attributable to legacy Ranger primarily due to an increase in employee costs of $3.1 million, or 70% of the remaining segment increase, and an increase in travel and repair and maintenance costs of $1.1 million, or 25% of the remaining segment increase.

Processing Solutions. Processing Solutions cost of services for 2016 decreased $5.3 million, or 67%, to $2.6 million from $7.9 million for 2015. The decrease was primarily attributable to $4.0 million related to the strategic shift discussed above and $1.0 million for 2015 costs incurred for a customer that lost its leasehold rights in certain land in the Bakken Shale.

General & Administrative. General and administrative expenses for 2016 increased $3.6 million, or 46%, to $11.4 million from $7.8 million for 2015. The increase in general and administrative expenses by segment was as follows:

Well Services. Well Services general and administrative expenses for 2016 increased $4.4 million, or 122%, to $8.0 million from $3.6 million for 2015. Magna and Bayou represented $4.0 million of the increase. The remaining $0.4 million increase was attributable to legacy Ranger primarily due to an increase in payroll and professional fees of $0.4 million, a $0.4 million increase in travel, office and insurance costs, offset by a $0.4 million decrease in bad debt expense.

Processing Solutions. Processing Solutions general and administrative expenses for 2016 decreased $0.8 million, or 19%, to $3.4 million from $4.2 million for 2015. The decrease was primarily attributable to a $0.6 million decrease in travel and office related expenses, a $0.4 million decrease in payroll and professional fees, offset by a $0.3 million increase in bad debt expense in 2016.

Depreciation and Amortization. Depreciation and amortization for 2016 increased $4.5 million, or 214%, to $6.6 million from $2.1 million for 2015. The increase in depreciation and amortization expense by segment was as follows:

Well Services. Well Services depreciation and amortization expense for 2016 increased $4.2 million, or 300%, to $5.6 million from $1.4 million for 2015. Magna and Bayou represented $3.1 million of the increase. The remaining $1.1 million increase was attributable to legacy Ranger primarily due to fixed assets that were placed in service during 2015, thus having a full year of depreciation for 2016.

Processing Solutions. Processing Solutions depreciation and amortization expense for 2016 increased $0.3 million, or 43%, to $1.0 million from $0.7 million for 2015. The increase related to fixed assets that were placed in service during 2015, thus having a full year of depreciation for 2016.

Impairment of Goodwill. Impairment for 2016 decreased $1.6 million, or 100%, to zero from $1.6 million for 2015 due to no goodwill impairment recorded in 2016 for our Processing Solutions segment.

Interest Expense, net. Interest expense, net for 2016 increased $0.2 million, or 67%, to $0.5 million from $0.3 million for 2015. The increase to interest expense, net by segment was as follows:

52


 

Well Services. Well Services interest expense, net for 2016 increased $0.3 million, or 300%, to $0.4 million from $0.1 million for 2015. The increase to interest expense, net was attributable to an increase in average borrowing during 2016.

Processing Solutions. Processing Solutions interest expense, net for 2016 decreased $0.1 million, or 50%, to $0.1 million from $0.2 million for 2015. The decrease to interest expense, net was attributable to a decrease in average borrowing during 2016.

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, acquisition‑related and severance costs, impairment of goodwill, costs incurred for offering-related 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), our most directly comparable financial measure calculated and presented in accordance with GAAP, to Adjusted EBITDA. 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Year Ended

 

 

December 31, 2017

 

 

 

    

Well

    

Processing

    

 

 

 

 

Other

 

Services

 

Solutions

 

Total

 

 

(in millions)

Net income (loss)

 

$

(16.2)

 

$

(11.9)

 

$

0.8

 

$

(27.3)

Interest expense, net

 

 

5.2

 

 

1.0

 

 

0.1

 

 

6.3

Tax expense

 

 

 —

 

 

0.4

 

 

 —

 

 

0.4

Depreciation and amortization

 

 

0.3

 

 

16.2

 

 

1.3

 

 

17.8

Equity based compensation

 

 

 —

 

 

1.1

 

 

0.1

 

 

1.2

Acquisition related and severance costs

 

 

3.7

 

 

4.1

 

 

0.2

 

 

8.0

Costs incurred for offering related services

 

 

1.0

 

 

3.8

 

 

 —

 

 

4.8

Adjusted EBITDA

 

$

(6.0)

 

$

14.7

 

$

2.5

 

$

11.2

 

53


 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Year Ended

 

 

December 31, 2016

 

    

 

    

Well

    

Processing

    

 

 

 

 

Other

 

Services

 

Solutions

 

Total

 

 

(in millions)

Net income (loss)

    

$

 —

    

$

(4.4)

 

$

(0.6)

 

$

(5.0)

Interest expense, net

 

 

 —

 

 

0.4

 

 

0.1