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 |
For the fiscal year ended December 31, 2018
OR
☐ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
Commission file number 001-38183
RANGER ENERGY SERVICES, INC.
(Exact name of registrant as specified in its charter)
Delaware | 81‑5449572 |
(State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.) |
800 Gessner Street, Suite 1000
Houston, Texas 77024
(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 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 every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐
Indicate by check mark 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 ☒ | 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, 2018, the aggregate market value of the registered Class A Common Stock of Ranger Energy Services, Inc. held by non-affiliates of the Registrant was $51.4 million, based on the closing market price as reported on the New York Stock Exchange of $9.17. As of February 26, 2019, the Registrant had 8,448,527 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 2019 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 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; |
• | 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 Part III, Item 8 of this Annual Report. In addition, please read “Cautionary Statement Regarding Forward-Looking Statements” and “Risk Factors” in Part I, Item 1A for information regarding certain risks inherent in our business.
Item 1. Business
Our Company
The Company is one of the largest providers of high specification (“high‑spec”) well service rigs and associated services in the United States, with a focus on technically demanding unconventional horizontal well completion and production operations. We believe that our fleet of 141 well service rigs is among the newest and most advanced in the industry and, based on our historical rig utilization and feedback from our customers, we believe that we are an operator of choice for U.S. onshore exploration and production (“E&P”) companies that require completion and production services at increasing lateral lengths. Our high‑specification well service rigs facilitate operations throughout the lifecycle of a well, including (i) completion services, such as milling out composite plugs after the hydraulic fracturing process and the installation of downhole production equipment; (ii) workover, including retrieval and replacement of existing production tubing; (iii) well maintenance, including replacement of downhole artificial lift components; and (iv) decommissioning, such as plugging and abandonment operations. The Company also provides Completion and Other Services, which provides services necessary to bring and maintain a well on production and primarily includes (i) wireline perforating and pumpdown services and (ii) snubbing services often utilized in conjunction with our high-spec rigs to convey equipment in and out of a well during completion and workover activities. The Company provides rental equipment, including well control packages, hydraulic catwalks and other equipment that are often deployed with our well service rigs. In addition, the Company owns and operates a fleet of proprietary, modular natural gas processing equipment that processes rich natural gas streams at the wellhead or central gathering points. The Company has operations in most of the active oil and natural gas basins in the United States, including the Permian Basin, the Denver‑Julesburg Basin, the Bakken Shale, the Eagle Ford Shale, the Haynesville Shale, the Gulf Coast and the South Central Oklahoma Oil Province (“SCOOP”) and Sooner Trend Anadarko Basin Canadian and Kingfisher counties (“STACK”) plays.
Our customers, which include many of the leading U.S. onshore E&P operators such as EOG Resources, Inc., Centennial Resource Development, Inc., Anadarko Petroleum Corporation, Sable Permian Resources Land, LLC and Concho Resources Inc., 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. Further, 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, 2018, all but one of our well service rigs meets these specifications, and approximately 84% of our high-spec 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 remaining rig in our fleet is generally deployed only for plugging and abandonment operations of conventional vertical wells.
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 the Company accepted delivery of 28 high‑spec well service rigs periodically in 2017 and 2018. Following delivery of the rigs from NOV, the Company's well service rig fleet expanded to 141 rigs,
1
of which 140 are high‑spec. The following table provides summary information regarding our high‑spec well service rig fleet. For additional information related to our high-spec rigs, please see “Properties—Equipment—High Specification Rigs” in Part I, Item 2 of this Annual Report.
HP Rating(1) | Mast Height | Mast Rating(2) | Number of High‑Spec Rigs | |||
550-600 | 112’ ‑ 117’ | 250,000 - 300,000 | 59 | |||
500 | 104’ ‑ 108’ | 240,000 - 250,000 | 59 | |||
450 - 475 | 102’ ‑ 104’ | 200,000 - 250,000 | 23 | |||
Total | 141 | |||||
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 and is measured in pounds. |
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.
In addition to our core well service rig operations, we offer a suite of completion and other services, including wireline perforating and pump down services, snubbing services often utilized in conjunction with our high spec rigs, well testing equipment and services used to control and separate completion fluids, hydrocarbons and solids after fracturing and transportation and fluid management services. These services are necessary to bring a well to production. Our complementary completion and other 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 through our processing solutions segment. We have developed a premium offering that includes proprietary designs on modern processing equipment, including modular Mechanical Refrigeration Units (“MRUs”). Our fleet of 29 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 of natural gas liquids (“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.
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.
Ranger was 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
2
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.
The following diagram indicates our current ownership structure as a result of the Offering and the transactions related thereto:
_________________________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. |
3
Our Segments
We conduct our operations through three segments: High Specification Rigs, Completion and Other Services and Processing Solutions. Our High Specification Rig Services segment provides well service rigs and complementary equipment and services in the United States, with a focus on technically demanding unconventional horizontal well completion, workover and maintenance operations. These services are fundamental to establishing and maintaining the flow of oil and natural gas throughout the productive life of a well. Our Completion and Other Services segment provides services necessary to bring and maintain a well on production and consists primarily of our wireline and snubbing lines of business. 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 incur corporate and administrative costs that are not specific to any of the operating segments, which are reported as other. For further information regarding the results of operations for each segment, please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Results of Operations” in Item 7 and Part IV, Note 15 — Segment Reporting of this Annual Report.
We have made certain reclassifications to our prior period amounts due to the change in reportable segments whereby our High Specification Rigs and Completion and Other Services segments were bifurcated from our legacy Well Services segment, as a result of our fourth quarter 2018 operating segment changes. None of these reclassifications have an impact on our consolidated operating results, cash flows or financial position.
High Specification Rigs and Related Services
Our high‑spec well service rigs facilitate operations throughout the lifecycle of a well, including, as described in greater detail below, (i) completion (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 high specification 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. |
4
In addition to our core well service rig operations, we also offer well service‑related equipment rentals, as described below.
• | 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. |
Completion and Other Services
Our Completion and Other Services segment provides services necessary to bring and maintain a well on production and consists primarily of our wireline and snubbing lines of business along with other, non-rig well services.
• | 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 primarily for well completion, but also for well intervention, pipe recovery, plugging and abandonment purposes. |
• | 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. |
• | 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. |
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
We provide services in various geographic regions across the United States, which are highly competitive. Our competitors include many large and small oilfield service providers. Our largest competitors in the high specification rig and completion 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
5
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 and the key factor driving demand for our services is the level of drilling activity by E&P companies. In turn, the level of drilling 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. Increased capital expenditures also lead to greater production, which historically has resulted in increased inventories and reduced prices consequently reducing demand for oilfield services. The results of our operations, therefore, may fluctuate from period to period, 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 of capital expenditure budgets. Our most notable declines occur in the first and fourth quarters of the calendar year. 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 fall and winter. 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 EOG Resources, Inc., Centennial Resource Development, Inc., Anadarko Petroleum Corporation, Sable Permian Resources Land, LLC and Concho Resources Inc. During 2018, we worked for approximately 200 distinct customers. During 2018, EOG Resources, Inc. accounted for approximately 20% of our revenues. During 2017, EOG Resources, Inc. and PDC Energy, Inc. 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.
Our top five customers represented approximately 42% and 47% of our consolidated revenues for 2018 and 2017, respectively. Within our High Specification Rig segment, our top five customers represented approximately 45% and 49% of the segment revenues for 2018 and 2017, respectively. Within our Completion and Other Services segment, our top five customers represented approximately 68% and 70% of our revenues for 2018 and 2017, respectively. Within our Processing Solutions segment, our top five customers represented approximately 82% and 92% of our revenues for 2018 and 2017, 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
6
supplied for our operations. We are not dependent on any single source of supply for those parts, supplies or materials. We have generally been able to obtain the equipment, parts and supplies necessary to support our operations on a timely basis.
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.
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
7
NORM contaminated land for unrestricted use under the Resource Conservation and Recovery Act (“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 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 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 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
8
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 necessitate that our customers limit disposal well volumes, disposal rates or disposal locations, or may require our customers or third party disposal well operators that dispose of customer wastewater to shut down disposal wells, which could adversely affect our customers’ business and result in a corresponding decrease in the need for our services, which could have a material adverse impact 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. Both the stay and the underlying rules have been the subject of litigation. In September 2018, the EPA proposed revisions to the 2016 rules, which, according the EPA, are intended to “streamline implementation, reduce duplicative EPA and state requirements, and significantly decrease unnecessary burdens on domestic energy producers.” Future implementation of these standards is uncertain at this time. In addition, some of our customers may operate on federal or tribal lands, and are subject to further regulation, including by tribal authorities and the federal Bureau of Land Management (“BLM”). Potentially applicable regulations include EPA's June 2016 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. In April 2018, the EPA proposed revisions to reportedly streamline the FIP. Neither the FIP nor the revisions 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. In September 2018, the BLM published a revised rule which rescinded and revised several components of the 2016 rule. The venting and flaring rule is also the subject of pending litigation. Additionally, 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
9
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 (the “Paris 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 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. Such withdrawal has not yet been finalized, and it is not possible at this time to predict how or when the United States might impose restrictions on GHGs as a result of the Paris Agreement. Further, several states and local governments have stated their commitment to its principles in their effectuation of policy and regulations. Still, new legislation or regulatory programs that restrict emissions of GHGs could adversely affect our operations and demand for our services. 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 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 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
10
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 effect 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.
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 requirements related to testing and weight and dimension specifications of equipment, drug testing and product handling. 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 driven 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, 2018, we had approximately 1,074 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 Securities and Exchange Commission (“SEC”) under the Exchange Act. The SEC 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.
11
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
You should carefully consider the information in this Annual Report, including the matters addressed under “Cautionary Statement 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.
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 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”) and other countries, such as Russia, 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; |
• | sanctions and other restrictions placed on oil producing countries, such as Iran and Venezuela; |
• | 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; |
12
• | 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. |
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 two years, the posted West Texas Intermediate (“WTI”) price for oil has ranged from a low of $43 per Barrel (“Bbl”) in 2017 to a high of $77 per Bbl in October 2018. 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. |
13
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 42% and 47% of our consolidated revenues for 2018 and 2017, respectively. Within our High Specification Rig segment, our top five customers represented approximately 45% and 49% of our revenues for 2018 and 2017, respectively. Within our Completion and Other Services segment, our top five customers represented approximately 68% and 70% of our revenues for 2018 and 2017, respectively. Within our Processing Solutions segment, our top five customers represented approximately 82% and 92% of our revenues for 2018 and 2017, respectively. During 2018, EOG Resources, Inc. accounted for approximately 20% of our revenues. 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 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.
14
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 60% of our high‑spec well service rigs were manufactured by NOV. 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 Acquisition 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; |
• | 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.
15
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 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
16
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.
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 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.
17
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 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. Oklahoma regulators further promulgated in February 2018 rules to regulate and reduce seismicity induced by underground injection. Additionally, from time to time regulators develop and implement plans directing certain wells located in proximity to seismic incidents to restrict or suspend disposal well operations. Similarly, 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.
18
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, 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
19
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. In September 2018, the BLM published a revised rule which rescinded and revised several components of the 2016 rule, which is the subject of pending litigation. 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.
The EPA also issued a FIP in June 2016 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. Neither the FIP nor the revisions 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.
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 at this time.
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.
20
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 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. 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. In September 2018, the EPA proposed revisions to the 2016 rules, which, according to the EPA, are intended to “streamline implementation, reduce duplicative EPA and state requirements, and significantly decrease unnecessary burdens on domestic energy producers.” Future implementation of these standards 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 nations 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. Such withdrawal has not yet been finalized as the Paris Agreement has a four year exit process. Further, several states and local governments have stated their commitment to its principles in their effectuation of policy and regulations. It is not possible at this time to predict how or when the United States might impose restrictions on GHGs as a result of the Paris Agreement, nor is it possible to predict how or when states will implement similar requirements.
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.
On August 16, 2017, in connection with the Offering and the ESCO Acquisition the Company issued $7.0 million of seller’s notes as partial consideration for the ESCO Acquisition. These notes included a note for $1.2 million, which was paid in August 2018 and a note for $5.8 million due in February 2019, for which we have exercised our rights to suspend payment pending resolution of certain indemnification claims. The notes bear interest at 5.0% payable quarterly until their respective maturity dates.
As of December 31, 2018, we had borrowed $18.5 million under our senior secured revolving credit facility (the “Credit Facility”) with a residual $17.7 million in borrowing capacity.
21
On June 22, 2018, the Company entered into the Master Financing and Security Agreement (“Financing Agreement”) with Encina Equipment Finance SPV, LLC. The amount available to be provided by the Lender to the Company under the Financing Agreement was contemplated to be not less than $35.0 million, and not to exceed $40.0 million. The first financing was required to be in an amount up to $22.0 million, which was used by the Company to acquire certain capital equipment. Subsequent to the first financing, the Company borrowed an additional $17.8 million, net of expenses, under the Financing Agreement. As of December 31, 2018, the aggregate principal balance outstanding was $37.5 million under the Financing Agreement. The Financing Agreement is secured by a lien on certain high specification rig assets.
In addition, subject to the limits contained in our Credit Facility and our Financing Agreement, 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:
• | 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 prior financing agreement and we may have similar difficulties with the 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.
22
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 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.
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
23
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.
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.
24
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.
We depend on information technology systems that we manage, and others that are managed by our third-party service and equipment providers, to conduct our day-to-day operations, including critical systems, and these systems are subject to risk associated with cyber incidents or attacks. Our technology systems and networks, and those of our vendors, suppliers and other business partners, may become the target of cyberattacks or information security breaches. These cyber security risks could disrupt our operations and result in downtime or the loss, theft, corruption or unauthorized release of critical data of us or those with whom we conduct business, as well as result in higher costs to correct and remedy the effects of such incidents. Certain cyber incidents, such as surveillance, may remain undetected for an extended period of time. 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 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 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
25
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 identified a material weakness in our internal control over financial reporting in the prior year 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”). 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. As of December 31, 2017, we identified a material weakness related to non-routine and/or complex transactions attributable to the lack of sufficient qualified accounting personnel. To remediate the prior year material weakness, we have recruited technical, financial and accounting personnel and have made significant advancements to our internal controls surrounding non-routine and complex arrangements to strengthen our financial reporting process since the Offering in August 2017. Based on testing performed by management, we believe the implemented controls are operating effectively and the prior year material weakness has been remediated as of December 31, 2018.
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.
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 60.3% 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”). 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
26
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.
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
27
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 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 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
28
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.
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 February 26, 2019, we had 8,448,527 shares of Class A Common Stock outstanding, which may be resold immediately in the public market. As of February 26, 2019, 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.
Through its interests in the Existing Owners, CSL holds 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:
• | 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 |
29
• | 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 and/or a smaller reporting company, we will not be required to comply with certain reporting requirements that apply to other public companies.
We are classified as an “emerging growth company” under the JOBS Act and as a “smaller reporting company” under the Exchange 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. For as long as we are a smaller reporting company, we will have certain other reduced disclosure obligations with the SEC, including the ability to provide only two years of audited financial statements and corresponding Management's Discussion and Analysis disclosures. We will remain a smaller reporting company until the aggregate market value of our outstanding common stock held by non-affiliates, calculated as of the end of our most recently complete second fiscal quarter exceeds $250 million. We cannot predict whether investors will find our common stock less attractive because of our reliance on any of these exemptions. If some investors find our common stock less attractive, there may be a less active trading market for our common stock and our stock price may be more volatile.
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 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.
30
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 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.
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
31
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 as of December 31, 2018 the present value of the estimated termination payments would, in the aggregate, be approximately $7.1 million (calculated using a discount rate equal to one-year LIBOR plus 150 basis points, applied against an undiscounted liability of approximately $10.4 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. During 2017, policymakers announced that LIBOR will be replaced by a Secured Overnight Financing Rate (“SOFR”) by 2021. The new benchmark rate will be based on overnight Treasury General Collateral repossession rates. We will monitor the continuous emergence of SOFR, as it could adversely impact our interest rate risk, and therefore the amount of interest we pay on liabilities currently measured at LIBOR.
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 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
32
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, 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.
33
Item 2. Properties
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, where our existing lease expires in 2020. At December 31, 2018, we owned or leased 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 | High Specification Rigs | |||||
Bowie, Texas | Maintenance Facility/Yard/Field Office | 3,100 sq ft/ 1 acre | Leased | 2020 | High Specification Rigs | |||||
Dickinson, North Dakota | Maintenance Facility/Yard/Field Office | 11,120 sq ft/3.5 acres | Owned | N/A | High Specification Rigs | |||||
Milliken, Colorado | Maintenance Facility/Yard/Field Office | 124,000 sq ft/23 acres | Owned | N/A | High Specification Rigs | |||||
Monahans, Texas | Maintenance Facility/Yard | 6,400 sq ft/ 10 acres | Leased | 2020 | High Specification Rigs | |||||
Newtown, North Dakota | Maintenance Facility/Yard/Field Office | 10,000 sq ft/3.5 acres | Owned | N/A | High Specification Rigs | |||||
Odessa, Texas | Maintenance Facility/Yard/Field Office | 5,000 sq ft/5 acres | Leased | 2020 | High Specification Rigs | |||||
Pleasanton, Texas | Maintenance Facility/Yard/Field Office | 7,800 sq ft/3 acres | Owned | N/A | High Specification Rigs | |||||
San Angelo, Texas | Maintenance Facility/Yard/Field Office | 12,055 sq ft/ 10 acres | Leased | 2020 | High Specification Rigs | |||||
Wharton, Texas | Field Office/Yard | 2,000 sq ft/4 acres | Leased | 2018 | High Specification Rigs | |||||
Williston, North Dakota | Maintenance Facility/Yard/Field Office | 10,820 sq ft/4.5 acres | Leased | 2018 | High Specification Rigs | |||||
Palestine, Texas | Maintenance Facility/Yard/Field Office | 2,000 sq ft/3.0 acres | Leased | 2020 | High Specification Rigs | |||||
Hobbs, New Mexico | Maintenance Facility/Yard/Field Office | 7,500 sq ft/3.4 acre | Leased | 2020 | High Specification Rigs | |||||
Calumet, Oklahoma | Maintenance Facility/Yard/Field Office | 7310 sq ft/3 acres | Leased | 2020 | High Specification Rigs | |||||
Midland, TX | Maintenance Facility/Yard/Field Office | 36,231 sq ft/12 acres | Leased | 2027 | High Specification Rigs | |||||
We also lease several smaller facilities, which leases generally have shorter terms. 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
High Specification Rigs
We have 141 well service rigs in our fleet, 140 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. In February 2017, we entered into the NOV Purchase Agreement, pursuant to which we accepted delivery of 28 high-spec rigs in 2017 and 2018. As a result of the NOV Purchase Agreement, our well service rig fleet expanded to 141 rigs, 140 of which are 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 60% of our existing high‑spec well service rigs were manufactured by NOV, with the remaining manufactured by Dragon/Cooper, Service King, Rig Works, Taylor, Mustang and Stewart & Stevenson Crown.
34
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, pipe racks, power swivels, ram block assemblies, rig pumps and related items.
Completion and Other Services
Our wireline services involve the use of wireline trucks and high-pressure pump trucks to pump fracturing plugs and perforating guns into extended reach horizontal wells for pump down perforating completion purposes. Our other services utilize trucks, pumps and other tools and equipment units to enable operators to safely run or remove pipe and other downhole tools from a pressurized well, control and separate completion fluids and to haul oilfield fluids used in production.
Processing Solutions
We have a fleet of 29 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 range of projects and natural gas volumes. Our MRUs can generate temperatures downwards of -20 degrees Fahrenheit. In addition, we own and operate five auxiliary NGL stabilizer units (designed to assist our MRUs that require additional capacity to separate and capture valuable NGLs), 59 NGL storage tanks with bulkhead delivery systems and capacities of 18,000 gallons, 14 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. Information regarding legal proceedings is presented in “Note 13 — Commitments and Contingencies” to our consolidated financial statements included in Part II, Item 8 of this Annual Report on Form 10-K.
Item 4. Mine Safety Disclosure
Not applicable.
35
PART II
Item 5. Market for Registrant's Common Equity, Related Stockholders' 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 presents 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.
NYSE Stock Price | ||||||||||||||||
2018 | 2017 | |||||||||||||||
High | Low | High | Low | |||||||||||||
First quarter | $ | 11.39 | $ | 7.60 | ||||||||||||
Second quarter | $ | 10.24 | $ | 6.88 | ||||||||||||
Third quarter | $ | 10.78 | $ | 7.82 | $ | 15.70 | $ | 13.50 | ||||||||
Fourth quarter | $ | 8.65 | $ | 4.70 | $ | 15.05 | $ | 8.48 | ||||||||
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
As of February 26, 2019, the closing sales price of our common stock on the NYSE was $7.30 and there were approximately 50 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.
36
Stock Performance Graph
The graph below presents a comparison of the cumulative total return on our Class A Common Stock, assuming $100 was invested on August 10, 2017, the initial trading day for our common stock for the NYSE Composite Index and a self- determined peer group, which includes Basic Energy Services, Inc., Key Energy Services, Inc., Superior Energy Services, Inc., C&J Energy Services, Inc. and Pioneer Energy Services Corp.
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.
Issuer Purchase of Equity Securities
None.
37
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, | |||||||
2018 | 2017 | ||||||
(in millions, except per share and hourly amounts) | |||||||
Statement of operations data | |||||||
Operating Revenues | $ | 303.1 | $ | 154.0 | |||
Operating loss | $ | (2.1 | ) | $ | (20.6 | ) | |
Net loss | $ | (5.8 | ) | $ | (27.3 | ) | |
Net loss attributable to Ranger Energy Services, Inc. | $ | (3.3 | ) | $ | (6.6 | ) | |
Per share loss from continuing operations | |||||||
Basic | $ | (0.39 | ) | $ | (0.78 | ) | |
Diluted | $ | (0.39 | ) | $ | (0.78 | ) | |
Balance sheet data (at end of period) | |||||||
Working capital | $ | 2.2 | $ | (3.8 | ) | ||
Property, plant and equipment, net | $ | 229.8 | $ | 189.2 | |||
Total assets | $ | 302.5 | $ | 259.7 | |||
Long-term debt | $ | 44.7 | $ | 5.8 | |||
Shareholders' equity / net parent investment | $ | 192.0 | $ | 195.7 | |||
Other financial data | |||||||
Net cash provided by (used in) operating activities | $ | 27.6 | $ | (17.3 | ) | ||
Net cash (used in) investing activities | $ | (74.4 | ) | $ | (68.9 | ) | |
Net cash provided by financing activities | $ | 44.1 | $ | 88.1 | |||
Capital Expenditures | $ | 75.9 | $ | 56.9 | |||
Adjusted EBITDA (1) | $ | 41.1 | $ | 11.2 | |||
Rig Hours | 290,000 | 211,200 | |||||
Average Monthly Hours per rig | 176 | 194 | |||||
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. |
38
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 Statement 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
The Company is one of the largest providers of high specification (“high‑spec”) well service rigs and associated services in the United States, with a focus on technically demanding unconventional horizontal well completion and production operations. We believe that our fleet of 141 well service rigs is among the newest and most advanced in the industry and, based on our historical rig utilization and feedback from our customers, we believe that we are an operator of choice for U.S. onshore exploration and production (“E&P”) companies that require completion and production services at increasing lateral lengths. Our high‑specification well service rigs facilitate operations throughout the lifecycle of a well, including (i) completion services, such as milling out composite plugs used during hydraulic fracturing, wireline and snubbing services (ii) workover, including retrieval and replacement of existing production tubing; (iii) well maintenance, including replacement of downhole artificial lift components; and (iv) decommissioning, such as plugging and abandonment operations. The Company also provides Completion and Other Services, which provides services necessary to bring and maintain a well on production and primarily includes (i) wireline services, including well intervention, pipe recovery, plugging and abandonment and (ii) snubbing services, including well maintenance, workover and well completion activities. In addition to our core well services rig operations, we also offer a suite of complementary services, including equipment rentals, well control packages, hydraulic catwalks and other equipment that are often deployed with our well service rigs. The Company also owns and operates a fleet of proprietary, modular natural gas processing equipment that processes rich natural gas streams at the wellhead or central gathering points. The Company has operations in most of the active oil and natural gas basins in the United States, including the Permian Basin, the Denver‑Julesburg Basin, the Bakken Shale, the Eagle Ford Shale, the Haynesville Shale, the Gulf Coast and the SCOOP and Sooner Trend Anadarko Basin Canadian 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.
During the fourth quarter of 2018, the Company bifurcated the legacy Well Services segment into High Specification Rigs and Completion and Other Services due to the modifications made to its internal reporting and responsibilities of those reporting to the Chief Operating Decision Maker (“CODM”). As a result, the financial information being provided to the CODM
39
has been updated to align with our new internal organization, which resulted in a new reportable segment discussed further below. Future filings will be updated accordingly.
We conduct our operations through three segments: High Specification Rigs, Completion and Other Services and Processing Solutions. Our High Specification Rigs 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. Our Completion and Other Services segment consists primarily of our wireline and snubbing lines of business along with other non-rig well services. Our Processing Solutions segment has historically consisted of the results of operations of Torrent Services. Our High Specification Rig 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 Completion and Other Services segment provides services necessary to bring and maintain a well on production. 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 15 — 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 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.
In determining the appropriate amount of revenue to be recognized as we fulfill the obligations under its contracts with customers, the following steps must be performed at contract inception: (i) identification of the promised goods or services in the contract; (ii) determination of whether the promised goods or services are performance obligations, including whether they are distinct in the context of the contract; (iii) measurement of the transaction price, including the constraint on variable consideration; (iv) allocation of the transaction price to the performance obligation and (v) recognition of revenue when (or as) the Company satisfies each performance obligation.
We satisfy our performance obligation over time as the services are performed. The Company believes the output method is a reasonable measure of progress for the satisfaction of our performance obligations, which are satisfied over time, as it provides a faithful depiction of (i) our performance towards complete satisfaction of the performance obligation under the contract and (ii) the value transferred to the customer of the services performed under the contract. We invoice our customers upon completion of the specified services and collection generally occurs within the payment terms agreed with customers. Accordingly, there is no financing component to our arrangement with customers.
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).
40
Personnel costs associated with our operational employees represent a significant cost of our business. A substantial portion of our labor costs is attributable to our crews and is partly variable based on the requirements of specific customers and operations. A key component of personnel costs relates to the ongoing training of our employees, which improves safety rates and reduces attrition. We also incur costs to employ personnel to support 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, operating revenues, operating income (loss) and adjusted EBITDA.
In addition, within our High Specification Rig segment, our management intends to use additional metrics to analyze our activity levels and profitability. These metrics include, among others, rig hours and rig utilization.
Revenues
We analyze our revenues by comparing actual revenues to our internal projections for a given period and to prior periods to assess our performance. We believe that revenues are a meaningful indicator of the demand and pricing for our services.
Operating Income (Loss)
We analyze our operating income (loss), which we define as revenues less cost of services, general and administrative expenses, depreciation and amortization, impairment and other operating expenses, to measure our financial performance. We believe operating income (loss) is a meaningful metric because it provides insight on profitability and true operating performance based on the historical cost basis of our assets. We also compare operating income (loss) to our internal projections for a given period and to prior periods.
Adjusted EBITDA
We view Adjusted EBITDA, which is a non‑GAAP financial measure, as an important indicator of performance. We define Adjusted EBITDA as net income or loss before interest expense, net, income tax provision or 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” 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 High Specification Rigs 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 on an hourly basis during the period that a well service rig is actively working, making rig hours a useful metric for evaluating our profitability.
Rig Utilization
Within our High Specification Rigs segment, we analyze rig utilization as a further important indicator of our activity levels and profitability. We measure rig utilization by reference to average monthly hours per rig, which is calculated by dividing (a) the approximate, aggregate operating well service rig hours for the periods presented by (b) the aggregate number of high specification rigs in our fleet during such period, as aggregated on a monthly basis utilizing a mid-month convention whereby a high specification rig is added to our fleet during a month, meaning that we have taken delivery of such high specification 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.
41
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, 2018 and 2017 our rig utilization as measured by average monthly hours per rig was approximately 176 and 194, respectively. Actual aggregate operating well service rig hours for the years ending December 31, 2018 and 2017 were 290,000 and 211,200, respectively. The increase in the rig hours is primarily as a result of our full year activity from the 2017 ESCO Acquisition and their associated high specification rigs, as well as newly acquired service rigs. The decrease in rig utilization resulted from the average number of high specification rigs in our active fleet, from 91 in 2017 to 137 in 2018, increasing at a greater rate than our number of hours.
Factors Impacting the Comparability of Results of Operations
ESCO Acquisition
Our Predecessor’s historical consolidated financial statements for the years ended December 31, 2017 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 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 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.”
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
42
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.
Results of Operations
The Year Ended December 31, 2018 compared to the Year Ended December 31, 2017
The following table presents our results of operations for the year ended December 31, 2018 as compared to the year ended December 31, 2017
Year Ended December 31, | Variance | ||||||||||||||
2018 | 2017 | $ | % | ||||||||||||
Revenues | |||||||||||||||
High specification rigs | $ | 149.9 | $ | 108.3 | $ | 41.6 | 38 | % | |||||||
Completion and other services | 136.0 | 37.4 | 98.6 | 264 | % | ||||||||||
Processing solutions | 17.2 | 8.3 | 8.9 | 107 | % | ||||||||||
Total revenues | 303.1 | 154.0 | 149.1 | 97 | % | ||||||||||
Operating expenses | |||||||||||||||
Cost of services (exclusive of depreciation and amortization) | |||||||||||||||
High specification rigs | 128.7 | 93.4 | 35.3 | 38 | % | ||||||||||
Completion and other services | 100.2 | 29.8 | 70.4 | 236 | % | ||||||||||
Processing solutions | 8.0 | 3.2 | 4.8 | 150 | % | ||||||||||
Total cost of services | 236.9 | 126.4 | 110.5 | 87 | % | ||||||||||
General and administrative | 29.0 | 30.4 | (1.4 | ) | (5 | )% | |||||||||
Depreciation and amortization | 30.3 | 17.8 | 12.5 | 70 | % | ||||||||||
Impairment of goodwill | 9.0 | — | 9.0 | 100 | % | ||||||||||
Total operating expenses | 305.2 | 174.6 | 130.6 | 75 | % | ||||||||||
Operating loss | (2.1 | ) | (20.6 | ) | 18.5 | (90 | )% | ||||||||
Other expenses | |||||||||||||||
Interest expense, net | (3.7 | ) | (6.3 | ) | 2.6 | 41 | % | ||||||||
Total other expenses | (3.7 | ) | (6.3 | ) | 2.6 | 41 | % | ||||||||
Loss before income tax expense | (5.8 | ) | (26.9 | ) | 21.1 | (78 | )% | ||||||||
Income tax expense | — | 0.4 | (0.4 | ) | (100 | )% | |||||||||
Net loss | $ | (5.8 | ) | $ | (27.3 | ) | $ | 21.5 | (79 | )% | |||||
Revenues. Revenues for the year ended December 31, 2018 increased $149.1 million, or 97%, to $303.1 million from $154.0 million for the year ended December 31, 2017. The increase in revenues by segment was as follows:
High Specification Rigs. High Specification Rig revenues for the year ended December 31, 2018 increased $41.6 million, or 38%, to $149.9 million from $108.3 million for the year ended December 31, 2017. The increase was primarily due to an increased number of rig hours, which increased 37% to 290,000 from 211,200 for the year ended December 31, 2018 compared to the year ended December 31, 2017. The total number of rig hours increased due to an increase in average rigs to 137 from an average of 91 rigs. The increases are primarily attributable to a full year of activity of the fixed assets and related services and equipment from the ESCO Acquisition and other fixed assets added to our fleet. Of the total segment increase, $17.5 million is attributable to the assets acquired in the ESCO Acquisition.
Completion and Other Services. Completion and Other Services revenues for the year ended December 31, 2018 increased $98.6 million, or 264%, to $136.0 million from $37.4 million for the year ended December 31, 2017. The increase is primarily
43
attributable to our wireline business, which accounted for approximately $95.0 million, or 96%, of the revenue increase, as the majority of this business commenced in the Permian Basin during the fourth quarter of 2017.
Processing Solutions. Processing Solutions revenues for the year ended December 31, 2018 increased $8.9 million, or 107%, to $17.2 million from $8.3 million for the year ended December 31, 2017. The increase was primarily attributable to an increase in MRU revenue due to an increased MRU utilization to 90% from 64% and an increase in our rental rates.
Cost of services. Cost of services for the year ended December 31, 2018 increased $110.5 million, or 87%, to $236.9 million from $126.4 million for the year ended December 31, 2017. As a percentage of revenue, cost of services was 78% and 82% for the years ended December 31, 2018 and 2017, respectively. The increase in cost of services by segment was as follows:
High Specification Rigs. High Specification Rig cost of services for the year ended December 31, 2018 increased $35.3 million, or 38%, to $128.7 million from $93.4 million for the year ended December 31, 2017. The increase was primarily attributable to an increase in expenses due to the expansion of the Company’s activities, which includes employee costs and repair and maintenance costs.
Completion and Other Services. Completion and Other Services cost of services for the year ended December 31, 2018 increased $70.4 million, or 236%, to $100.2 million from $29.8 million for the year ended December 31, 2017. The increase was primarily attributable to an increase in expenses due to the expansion of the Company’s activities, which includes employee costs.
Processing Solutions. Processing Solutions cost of services for the year ended December 31, 2018 increased $4.8 million, or 150%, to $8.0 million from $3.2 million for the year ended December 31, 2017. The increase was primarily attributable to increases in mobilization and installation costs incurred which corresponds with additional revenues.
General and administrative. General and administrative expenses for the year ended December 31, 2018 decreased $1.4 million, or 5%, to $29.0 million from $30.4 million for the year ended December 31, 2017. The decrease in general and administrative expenses is primarily due to a decrease in legal and other professional fees related to the initial public offering.
Depreciation and amortization. Depreciation and amortization for the year ended December 31, 2018 increased $12.5 million, or 70%, to $30.3 million from $17.8 million for the year ended December 31, 2017. The increase in depreciation and amortization expense was related to the fixed assets put in place during 2017 due to the acquisition of ESCO, as well as fixed asset additions in all operating segments during 2018.
Interest expense, net. Interest expense, net for the year ended December 31, 2018 decreased $2.6 million, or 41%, to $3.7 million from $6.3 million for the year ended December 31, 2017. The decrease to interest expense, net was attributable to the repayment of the Bridge Loan during 2017 by issuing Class A Common Stock and Ranger Units (and corresponding number of our Class B Common Stock) to the Bridge Loan Lenders during the year ended December 31, 2017, coupled with the lower average interest rate during 2018.
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 or loss before interest expense, net, income tax provision or benefit, depreciation and amortization, equity‑based compensation, acquisition‑related and severance costs, impairment of goodwill and other non-cash and certain 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.
44
The Year Ended December 31, 2018 compared to The Year Ended December 31, 2017
Year Ended December 31, 2018 | ||||||||||||||||||||
High Specification Rigs | Completion and Other Services | Processing Solutions | ||||||||||||||||||
Other | Total | |||||||||||||||||||
(in millions) | ||||||||||||||||||||
Net income (loss) | $ | (6.9 | ) | $ | 27.6 | $ | 7.7 | $ | (34.2 | ) | $ | (5.8 | ) | |||||||
Interest expense, net | — | — | — | 3.7 | 3.7 | |||||||||||||||
Tax expense | — | — | — | — | — | |||||||||||||||
Depreciation and amortization | 19.1 | 8.2 | 1.5 | 1.5 | 30.3 | |||||||||||||||
Equity based compensation | — | — | — | 2.1 | 2.1 | |||||||||||||||
IPO, acquisition and severance costs | 0.7 | — | — | 0.4 | 1.1 | |||||||||||||||
Loss on property and equipment | 0.7 | — | — | — | 0.7 | |||||||||||||||
Impairment of goodwill | 9.0 | — | — | — | 9.0 | |||||||||||||||
Adjusted EBITDA | $ | 22.6 | $ | 35.8 | $ | 9.2 | $ | (26.5 | ) | $ | 41.1 | |||||||||
Year Ended December 31, 2017 | ||||||||||||||||||||
High Specification Rigs | Completion and Other Services | Processing Solutions | ||||||||||||||||||
Other | Total | |||||||||||||||||||
(in millions) | ||||||||||||||||||||
Net income (loss) | $ | (9.9 | ) | $ | (2.0 | ) | $ | 0.8 | $ | (16.2 | ) | $ | (27.3 | ) | ||||||
Interest expense, net | 1.0 | — | 0.1 | 5.2 | 6.3 | |||||||||||||||
Tax expense | 0.4 | — | — | — | 0.4 | |||||||||||||||
Depreciation and amortization | 10.8 | 5.4 | 1.3 | 0.3 | 17.8 | |||||||||||||||
Equity based compensation | 1.1 | — | 0.1 | — | 1.2 | |||||||||||||||
IPO, acquisition and severance costs | 7.9 | — | 0.2 | 4.7 | 12.8 | |||||||||||||||
Loss on property and equipment | — | — | — | — | — | |||||||||||||||
Impairment of goodwill | — | — | — | — | — | |||||||||||||||
Adjusted EBITDA | $ | 11.3 | $ | 3.4 | $ | 2.5 | $ | (6.0 | ) | $ | 11.2 | |||||||||
$ Variance | ||||||||||||||||||||
High Specification Rigs | Completion and Other Services | Processing Solutions | ||||||||||||||||||
Other | Total | |||||||||||||||||||
(in millions) | ||||||||||||||||||||
Net income (loss) | $ | 3.0 | $ | 29.6 | $ | 6.9 | $ | (18.0 | ) | $ | 21.5 | |||||||||
Interest expense, net | (1.0 | ) | — | (0.1 | ) | (1.5 | ) | (2.6 | ) | |||||||||||
Tax expense | (0.4 | ) | — | — | — | (0.4 | ) | |||||||||||||
Depreciation and amortization | 8.3 | 2.8 | 0.2 | 1.2 | 12.5 | |||||||||||||||
Equity based compensation | (1.1 | ) | — | (0.1 | ) | 2.1 | 0.9 | |||||||||||||
IPO, acquisition related and severance costs | (7.2 | ) | — | (0.2 | ) | (4.3 | ) | (11.7 | ) | |||||||||||
Loss on property and equipment | 0.7 | — | — | — | 0.7 | |||||||||||||||
Impairment of goodwill | 9.0 | — | — | — | 9.0 | |||||||||||||||
Adjusted EBITDA | $ | 11.3 | $ | 32.4 | $ | 6.7 | $ | (20.5 | ) | $ | 29.9 | |||||||||
Adjusted EBITDA for the year ended December 31, 2018 increased $29.9 million to $41.1 million from $11.2 million for the year ended December 31, 2017. The increase by segment was as follows:
High Specification Rigs. High Specification Rigs Adjusted EBITDA increased $11.3 million to $22.6 million from $11.3 million primarily due to an increase in revenues of $41.6 million partially offset by a corresponding increase in cost of services of $35.3 million.
45
Completion and Other Services. Completion and Other Services Adjusted EBITDA increased $32.4 million to $35.8 million from $3.4 million primarily due to an increase in revenues of $98.6 million partially offset by a corresponding increase in cost of services of $70.4 million.
Processing Solutions. Processing Solutions Adjusted EBITDA increased $6.7 million to $9.2 million from $2.5 million primarily due to an increase in net income of $6.9 million.
Other. Adjusted EBITDA for the year ended December 31, 2018 was a loss of $26.5 million primarily due to general and administrative expenses of $29.0 million, related to compensation and benefits, professional fees and other general expenses. The balances included in Other reflect the general and administrative costs, interest expense, net and tax expense or benefit not directly attributable to any of our Segments.
46
Liquidity and Capital Resources
Overview
We require capital to fund ongoing operations, including maintenance expenditures on our existing fleet and equipment, organic growth initiatives, investments and acquisitions. Our primary sources of liquidity have been capital contributions from our owners and commercial borrowings and proceeds from the Offering. We expect our primary sources of liquidity will be cash generated from operations and borrowings under our Credit Facility. We strive to maintain financial flexibility and proactively monitor potential capital sources to meet our investment and target liquidity requirements and to permit us to manage the cyclicality associated with our business.
On August 16, 2017, we completed the Offering 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 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 and paid $3.9 million in offering related costs and $0.7 million for cash bonuses to certain employees. The remaining net proceeds were used to fund capital expenditures and general business expenses.
As of December 31, 2018, we had approximately $2.6 million of cash on hand, operating cash flows of $27.6 million and availability under our Revolving Credit Facility of $17.7 million. Additionally, with the borrowing capacity under the Financing Agreement, we are expected to have sufficient funds to meet the Company’s liquidity requirements for at least the next 12 months.
Cash Flows
The following table presents our cash flows for the periods indicated:
Year Ended December 31, | Variance | ||||||||||||||
2018 | 2017 | $ | % | ||||||||||||
(in millions) | |||||||||||||||
Cash flows provided by (used in) operating activities | $ | 27.6 | $ | (17.3 | ) | $ | 44.9 | (260 | )% | ||||||
Cash flows used in investing activities | (74.4 | ) | (68.9 | ) | (5.5 | ) | 8 | % | |||||||
Cash flows provided by financing activities | 44.1 | 88.1 | (44.0 | ) | (50 | )% | |||||||||
Net change in cash | $ | (2.7 | ) | $ | 1.9 | $ | (4.6 | ) | (242 | )% | |||||
Operating Activities
Net cash provided by operating activities increased $44.9 million to $27.6 million for the year ended December 31, 2018 compared to net cash used of $17.3 million for the year ended December 31, 2017. The increase in cash flows provided by operating activities is attributable to a lower net loss for the Company during the current period, partially offset by an increase in depreciation and amortization and the impairment of goodwill. The use of working capital cash for the year ended December 31, 2018 increased to $7.2 million as compared to the use of working capital cash of $14.5 million during the year ended December 31, 2017.
Investing Activities
Net cash used in investing activities increased $5.5 million to $74.4 million for the year ended December 31, 2018 compared to $68.9 million for the year ended December 31, 2017. The increase in cash flows used in investing activities is primarily attributable to fixed asset additions and extended payments for high specification rigs received during the year ended December 31, 2018.
Financing Activities
Net cash provided by financing activities decreased $44.0 million to $44.1 million for the year ended December 31, 2018 compared to $88.1 million for the year ended December 31, 2017. The decrease in cash flows provided by financing activities is primarily attributable to the proceeds from the Offering of $80.8 million, net of underwriters’ expense of $4.2 million, as well as the proceeds from related party debt of $21.0 million during the year ended December 31, 2017, which was partially offset by $56.0 million and $39.1 million borrowings of our credit facility and long-term debt, respectively and payments of $41.4 million and $9.6 million on our outstanding debt and capital leases, respectively.
47
Supplemental Disclosures
We added assets during 2017, where cash payments approximated $15.5 million during the current period. In addition, we also purchased $11.1 million in assets via capital lease financing.
Working Capital
Our working capital, which we define as total current assets less total current liabilities, totaled a $2.2 million surplus and a $3.8 million deficit at and December 31, 2018 and December 31, 2017, respectively.
Our Debt Agreements
In connection with the Offering and the ESCO Acquisition, we issued $7.0 million of seller's notes as a partial consideration for the ESCO Acquisition. These notes include a note for $1.2 million, which was paid in August 2018 and a note for $5.8 million due in February 2019. Both of these notes bear interest at 5.0% payable quarterly until their respective maturity dates.
In connection with the Offering, we entered into a new credit agreement providing for our $50.0 million Credit Facility. The Credit Facility is subject to a borrowing base that is calculated based upon a percentage of the value of our eligible accounts receivable less certain reserves. The borrowing base is calculated on a monthly basis pursuant to a borrowing base certificate delivered by us to the Administrative Agent. The Credit Facility is used for capital expenditures and permitted acquisitions, to provide for working capital requirements and for other general corporate purposes. The Credit Facility is secured by certain of our assets and contains various affirmative and negative covenants and restrictive provisions. We had approximately $36.2 million of borrowing capacity with $17.7 million available under the Credit Facility as of December 31, 2018.
The Credit Facility permits extensions of credit up to the lesser of $50.0 million and a borrowing base that is determined by calculating the amount equal to the sum of (i) 85% of the Eligible Accounts (as defined in the Credit Facility), less the amount, if any, of the Dilution Reserve (as defined in the Credit Facility), minus (ii) the aggregate amount of Reserves (as defined in the Credit Facility), if any, established by the Administrative Agent from time to time pursuant to the Credit Facility. The borrowing base is calculated on a monthly basis pursuant to a borrowing base certificate delivered by the Borrower to the Administrative Agent.
Borrowings under the Credit Facility bear interest, at our election, at either the (a) one-, two-, three- or six-month LIBOR or (b) the greatest of (i) the federal funds rate plus ½%, (ii) the one-month LIBOR plus 1% and (iii) the Base Rate, in each case plus an applicable margin, and interest shall be payable monthly in arrears. The applicable margin for LIBOR loans ranges from 1.50% to 2.00% and the applicable margin for Base Rate loans ranges from 0.50% to 1.00%, in each case, depending on our average excess availability under the Credit Facility. The applicable margin for LIBOR loans was 1.75% and the applicable margin for Base Rate loans is 1.50% until December 31, 2018. During the continuance of a bankruptcy event of default, automatically and during the continuance of any other default, upon the Administrative Agent’s or the required lenders’ election, all outstanding amounts under the Credit Facility bears interest at 2.00% plus the otherwise applicable interest rate. The Credit Facility is scheduled to mature on the fifth anniversary of the consummation of the Offering (August 16, 2022). As of December 31, 2018 the Credit Facility had an interest rate of 4.1%.
In addition, the Credit Facility restricts our ability to make distributions on, or redeem or repurchase, our equity interests, except for certain distributions, including distributions of cash so long as, both at the time of the distribution and after giving effect to the distribution, no default exists under the Credit Facility and either (a) excess availability at all times during the preceding 90 consecutive days, on a pro forma basis and after giving effect to such distribution, is not less than the greater of (1) 22.5% of the lesser of (A) the maximum revolver amount and (B) the then-effective borrowing base and (2) $10.0 million or (b) if our fixed charge coverage ratio is at least 1.0x on a pro forma basis, excess availability at all times during the preceding 90 consecutive days, on a pro forma basis and after giving effect to such distribution, is not less than the greater of (1) 17.5% of the lesser of (A) the maximum revolver amount and (B) the then-effective borrowing base and (2) $7.0 million. If the foregoing threshold under clause (b) is met, we may not make such distributions (but may make certain other distributions, including under clause (a) above) prior to the earlier of the date that is (a) 12 months from closing or (b) the date that our fixed charge coverage ratio is at least 1.0x for two consecutive quarters. Our Credit Facility generally permits us to make distributions required under the TRA, but a ‘‘Change of Control’’ under the TRA constitutes an event of default under our Credit Facility, and our Credit Facility does not permit us to make payments under the TRA upon acceleration of our obligations thereunder unless no event of default exists or would result therefrom and we have been in compliance with the fixed charge coverage ratio for the most recent 12-month period on a pro forma basis. Our Credit Facility also requires us to maintain a fixed charge coverage ratio of at least 1.0x if our liquidity is less than $10.0 million until our liquidity is at least $10.0 million for 30 consecutive days. We are not subject to a fixed charge coverage ratio if we have no drawings under the Credit Facility and have at least $20.0 million of qualified cash.
48
The Credit Facility contains events of default customary for facilities of this nature, including, but not limited, to:
• | events of default resulting from our failure or the failure of any guarantors to comply with covenants and financial ratios; |
• | the occurrence of a change of control; |
• | the institution of insolvency or similar proceedings against us or any guarantor; and |
• | the occurrence of a default under any other material indebtedness we or any guarantor may have. |
Upon the occurrence and during the continuation of an event of default, subject to the terms and conditions of the Credit Facility, the lenders are able to declare any outstanding principal of our Credit Facility debt, together with accrued and unpaid interest, to be immediately due and payable and exercise other remedies.
On June 22, 2018, the Company entered into a Financing Agreement with Encina Equipment Finance SPV, LLC (the “Lender”). The amount available to be provided by the Lender to the Company under the Financing Agreement was contemplated to be not less than $35.0 million, and not to exceed $40.0 million. The first financing was required to be in an amount up to $22.0 million, which was used by the Company to acquire certain capital equipment. Subsequent to the first financing, the Company borrowed an additional $17.8 million, net of expenses, under the Financing Agreement. We anticipate utilizing the additional net proceeds to acquire certain capital equipment. The Financing Agreement is secured by a lien on certain high specification rig assets. As of December 31, 2018, the aggregate principal balance outstanding was $37.5 million under the Financing Agreement. Amounts outstanding under the Financing Agreement are payable ratably over 48 months through the maturity of July 2022.
Borrowings under the Financing Agreement bear interest at a rate per annum equal to the sum of 8.0% plus the London Interbank Offered Rate (“LIBOR”), which was 2.4% as of December 31, 2018. The Financing Agreement requires that the Company maintain leverage ratios of 3.50 to 1.00 as of December 31, 2018 and 2.50 to 1.00 for periods thereafter. The Company was in compliance with the covenants under the Financing Agreement as of December 31, 2018.
During 2017, policymakers announced that LIBOR will be replaced by a SOFR by 2021. The new benchmark rate will be based on overnight Treasury General Collateral repossession rates. We will monitor the continuous emergence of SOFR, as it could adversely impact our interest rate risk, and therefore the amount of interest we pay on liabilities currently measured at LIBOR.
Contractual and Commercial Commitments
The following table summarizes our contractual obligations and commercial commitments as of December 31, 2018:
Total | Less than 1 year | 1 - 3 years | 3 - 5 years | More than 5 years | ||||||||||||||||
(in millions) | ||||||||||||||||||||
Debt obligations (1) | $ | 71.4 | $ | 19.9 | $ | 51.4 | $ | 0.1 | $ | — | ||||||||||
Capital lease obligations (1) | 12.0 | 5.0 | 6.9 | 0.1 | — | |||||||||||||||
Operating lease obligations | 10.5 | 2.9 | 3.9 | 2.2 | 1.5 | |||||||||||||||
Total | $ | 93.9 | $ | 27.8 | $ | 62.2 | $ | 2.4 | $ | 1.5 | ||||||||||
_________________________
1. | Debt and capital lease obligations include interest to be paid in future periods. |
49
Tax Receivable Agreement
With respect to obligations we expect to incur under our Tax Receivable Agreement (except in cases where we elect to terminate the Tax Receivable Agreement early, the Tax Receivable Agreement is terminated early due to certain mergers, asset sales, other forms of business combinations or other changes of control or we have available cash but fail to make payments when due), generally we may elect to defer payments due under the Tax Receivable Agreement if we do not have available cash to satisfy our payment obligations under the Tax Receivable Agreement or if our contractual obligations limit our ability to make these payments. Any such deferred payments under the Tax Receivable Agreement generally will accrue interest. 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. We intend to account for any amounts payable under the Tax Receivable Agreement in accordance with ASC 450, Contingencies. Further, we intend to account for the effect of increases in tax basis and payments for such increases under the Tax Receivable Agreement arising from future redemptions as follows:
• | when future sales or redemptions occur, we will record a deferred tax liability for the gross amount of the income tax effect along with an offset of 85% of this liability as payable under the Tax Receivable Agreement; the remaining difference between the deferred tax liability and tax receivable agreement liability will be recorded as additional paid‑in capital; and |
• | to the extent we have recorded a deferred tax asset for an increase in tax basis to which a benefit is no longer expected to be realized due to lower future taxable income, we will reduce the deferred tax asset with a valuation allowance. |
Critical Accounting Policies and Estimates
Our financial statements are prepared in accordance with GAAP. In connection with preparing our financial statements, we are required to make assumptions and estimates about future events, and apply judgments that affect the reported amounts of assets, liabilities, revenue, expense and the related disclosures. We base our assumptions, estimates and judgments on historical experience, current trends and other factors that management believes to be relevant at the time we prepare our consolidated financial statements. On a regular basis, management reviews the accounting policies, assumptions, estimates and judgments to ensure that our consolidated financial statements are presented fairly and in accordance with GAAP. However, because future events and their effects cannot be determined with certainty, actual results could differ materially from our assumptions and estimates.
Our significant accounting policies are discussed in our audited consolidated financial statements included elsewhere in this Annual Report. Management believes that the following accounting estimates are those most critical to fully understanding and evaluating our reported financial results, and they require management’s most difficult, subjective or complex judgments, resulting from the need to make estimates about the effect of matters that are inherently uncertain.
Property, Plant and Equipment
Policy description
Property, plant and equipment is stated at cost or estimated fair market value at the acquisition date less accumulated depreciation. Depreciation is charged to expense on the straight‑line basis over the estimated useful life of each asset, with estimated useful lives reviewed by management on an annual basis. Expenditures for major renewals and betterments are capitalized while expenditures for maintenance and repairs are charged to expenses as incurred. Assets under capital lease obligations and leasehold improvements are amortized over the shorter of the lease term or their respective estimated useful lives. Depreciation does not begin until property, plant and equipment is placed in service. Once placed in service, depreciation on property and equipment continues while being repaired, refurbished or between periods of deployment.
Judgments and assumptions
Accounting for our property, plant and equipment requires us to estimate the expected useful lives of our fleet and related equipment and any related salvage value. The range of estimated useful lives is based on overall size and specifications of the fleet, expected utilization along with continuous repairs and maintenance that may or may not extend the estimated useful lives. To the extent the expenditures extends the expected useful life, these expenditures are capitalized and depreciated over the extended useful life.
50
Long‑lived Asset Impairment
Policy description
We evaluate the recoverability of the carrying value of long‑lived assets, including property, plant and equipment and intangible assets, whenever events or circumstances indicate the carrying amount may not be recoverable. If a long‑lived asset is tested for recoverability and the undiscounted estimated future cash flows expected to result from the use and eventual disposition of the asset is less than the carrying amount of the asset, the asset cost is adjusted to fair value and an impairment loss is recognized as the amount by which the carrying amount of a long‑lived asset exceeds its fair value.
Judgments and assumptions
Our impairment analysis requires us to apply judgment in identifying impairment indicators and estimating future undiscounted cash flows of our fleets. If actual results are not consistent with our assumptions and estimates or our assumptions and estimates change due to new information, we may be exposed to an impairment charge. Key assumptions used to determine the undiscounted future cash flows include estimates of future fleet utilization and demands based on our assumptions around future commodity prices and capital expenditures of our customers.
Business Combinations
Policy description
We recognize, separately from goodwill, the identifiable assets acquired and liabilities assumed at their estimated acquisition date fair values. Fair value is the price that would be received to sell an asset or would be paid to transfer a liability in an orderly transaction between market participants at the measurement date. Goodwill as of the acquisition date is measured and recognized as the excess of: (i) the aggregate of the fair value of the consideration transferred, the fair value of any non‑controlling interest in the acquiree and the acquisition date fair value of our previously held equity interests over (ii) the fair value of assets acquired and liabilities assumed. These fair values are accounted for at the date of acquisition and included in the consolidated balance sheets as of December 31, 2017. There were no material business combinations that took place during the year ended December 31, 2018. The results of operations of an acquired business is included in the statement of operations from the date of the acquisition.
Judgments and assumptions
We estimate fair value based on the assumptions of market participants and not those of the reporting entity. Fair values are determined through the use of a blended market and income approach. Therefore, entity‑specific intentions do not impact the measurement of fair value. Changes to these assumptions could change the fair value estimates used in our business combination accounting.
Revenue Recognition
Policy description
Effective January 1, 2018, the Company adopted Accounting Standards Codification (“ASC”) Revenue from Contracts with Customers (“ASC 606”), using the modified retrospective method. This standard applies to all contracts with customers, except for contracts that are within the scope of other standards, such as leases, insurance, collaborative arrangements and financial instruments. Under ASC 606, an entity recognizes revenue when it transfers control of the promised goods or services to its customer, in an amount that reflects the consideration which the entity expects to receive in exchange for those goods or services. If control transfers to the customer over time, an entity selects a method to measure progress that is consistent with the objective of depicting its performance. The provisions of ASC 606 were applied to contracts not completed at January 1, 2018. There was no impact upon adoption of ASC 606. As a result, no disclosure of the impact for each financial statement line items is applicable.
In determining the appropriate amount of revenue to be recognized as the Company fulfills the obligations under its contracts with customers, the following steps must be performed at contract inception: (i) identification of the promised goods or services in the contract; (ii) determination of whether the promised goods or services are performance obligations, including whether they are distinct in the context of the contract; (iii) measurement of the transaction price, including the constraint on variable consideration; (iv) allocation of the transaction price to the performance obligations and (v) recognition of revenue when (or as) the Company satisfies each performance obligation.
We satisfy our performance obligation over time as the services are performed. The Company believes the output method is a reasonable measure of progress for the satisfaction of our performance obligations, which are satisfied over time, as it provides
51
a faithful depiction of (1) our performance toward complete satisfaction of the performance obligation under the contract and (2) the value transferred to the customer of the services performed under the contract. The Company has elected the right to invoice practical expedient for recognizing revenue. The Company invoices customers upon completion of the specified services and collection generally occurs within the payment terms agreed with customers. Accordingly, there is no financing component to our arrangements with customers.
Judgments and assumptions
Recording revenue involves the use of estimates and management judgment. We must make a determination at the time our services are provided whether the customer has the ability to make payments to us. While we do utilize past payment history, and, to the extent available for new customers, public credit information in making our assessment, the determination of whether collectability is reasonably assured is ultimately a judgment decision that must be made by management. We have disaggregated revenue and disclosed such disaggregation in a manner that is consistent with our reporting segments and further disaggregation is not considered to be useful to investors in understanding or assessing the results of operations or business.
Equity‑Based Compensation
Policy description
We record equity‑based payments at fair value on the date of the grant, and expense the value of these awards in compensation expense over the applicable vesting periods.
Judgments and assumptions
We estimate the fair value of our equity‑based compensation using an option pricing model that includes certain assumptions, such as volatility, dividend yield and risk free interest rate. Changes in these assumptions could change the fair value of our unit based awards and associated compensation expense in our consolidated statements of operations.
Recent Accounting Pronouncements
For information regarding new accounting policies or updates to existing accounting policies as a result of new accounting pronouncements, please refer to Recent Accounting Pronouncements included in Note 2 — Summary of Significant Accounting Policies in Item 8 of this Annual Report.
Off‑Balance Sheet Arrangements
We currently have no material off‑balance sheet arrangements.
Jumpstart Our Business Act of 2012
We are an “emerging growth company” as defined in the JOBS Act. We will remain an emerging growth company until the earlier of (1) the last day of our fiscal year (a) following the fifth anniversary of the completion of the Offering, (b) in which we have total annual gross revenue of at least $1.07 billion, or (c) in which we are deemed to be a large accelerated filer, which means the market value of our common stock that is held by non-affiliates exceeds $700.0 million as of the last business day of our most recently completed second fiscal quarter, and (2) the date on which we have issued more than $1.0 billion in non-convertible debt securities during the prior three-year period. An emerging growth company may take advantage of specified reduced reporting and other burdens that are otherwise applicable generally to public companies. We have irrevocably opted out of the extended transition period and, as a result, we will adopt new or revised accounting standards on the relevant dates on which adoption of such standards is required for other public companies.
Item 7A. Quantitative and Qualitative Disclosure about Market Risks
The demand, pricing and terms for oil and natural gas services provided by us are largely dependent upon the level of activity for the U.S. oil and natural gas industry. Industry conditions are influenced by numerous factors over which we have no control, including, but not limited to: the supply of and demand for oil and natural gas; the level of prices, and expectations about future prices of oil and natural gas; the cost of exploring for, developing, producing and delivering oil and natural gas; the expected rates of declining current production; the discovery rates of new oil and natural gas reserves; available pipeline and other transportation capacity; weather conditions; domestic and worldwide economic conditions; political instability in oil‑producing countries; environmental regulations; technical advances affecting energy consumption; the price and availability of alternative fuels; the ability of oil and natural gas producers to raise equity capital and debt financing; and merger and divestiture activity among oil and natural gas producers.
52
Interest Rate Risk
We are exposed to interest rate risk, primarily associated with our Credit Facility and Financing Agreement. We had an aggregate of $5.8 million outstanding under notes payable from the ESCO Acquisition as of December 31, 2018, with an interest rate of 5.0%. In addition, as of December 31, 2018, we had $18.5 million outstanding under our Credit Facility, with a weighted average interest rate of 4.1%. As of December 31, 2018, the aggregate principal balance outstanding was $37.5 million under the Financing Agreement, with a weighted average interest rate of 10.3%. A 1.0% increase or decrease in the weighted average interest rate would increase or decrease our interest expense by approximately $0.4 million annually. We do not currently hedge our interest rate exposure.
During 2017, policymakers announced that LIBOR will be replaced by a SOFR by 2021. The new benchmark rate will be based on overnight Treasury General Collateral repossession rates. We will monitor the continuous emergence of SOFR, as it could adversely impact our interest rate risk, and therefore the amount of interest we pay on liabilities currently measured at LIBOR.
Credit Risk
The majority of our trade receivables have payment terms of 30 days or less. As of December 31, 2018, the top three trade receivable balances represented 13%, 12% and 11%, respectively, of total accounts receivable. Within our High Specification Rig segment, the top three trade receivable balances represented 8%, 7% and 7%, respectively, of total High Specification Rig accounts receivable. Within our Completion and Other Services segment, the top three trade receivable balances represented 26%, 22% and 17%, respectively, of total Completion Services accounts receivable. Within our Processing Solutions segment, the top three trade receivable balances represented 49%, 18% and 12%, respectively, of total Processing Solutions accounts receivable. We mitigate the associated credit risk by performing credit evaluations and monitoring the payment patterns of our customers.
Commodity Price Risk
The market for our services is indirectly exposed to fluctuations in the prices of oil and natural gas to the extent such fluctuations impact the activity levels of our E&P customers. Any prolonged substantial reduction in oil and natural gas prices would likely affect oil and natural gas production levels and therefore affect demand for our services. We do not currently intend to hedge our indirect exposure to commodity price risk.
Item 8. Financial Statements and Supplementary Data
Our Consolidated Financial Statements, together with the report of our independent registered public accounting firm begin on page F-1 of this Annual Report and incorporated herein by reference.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosures
Not applicable.
Item 9A. Controls and Procedures
Evaluation of Disclosure Controls and Procedures
As required by Rule 13a‑15(b) under the Exchange Act, we have evaluated, under the supervision and with the participation of management, including our chief executive officer and chief financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d‑15(e) under the Exchange Act) as of the end of the period covered by this Annual Report on Form 10-K. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file or submit under the Exchange Act is accumulated and communicated to management, including our chief executive officer and chief financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Any controls and procedures, no matter how well designed and operated can only provide reasonable assurance of achieving the desired control objective and management necessarily applies its judgment in evaluating the cost-benefit relationship of all possible controls and procedures. Based upon this evaluation our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of the end of the period covered by this Annual Report, at a reasonable assurance level.
53
Management's Annual Report on Internal Control Over Financial Reporting
Management is responsible for establishing and maintaining adequate internal control over financial reporting as such term is defined in Exchange Act Rule 13a-15(f).
The internal control over financial reporting is a process designed under the supervision and with the participation of our principal executive officer and principal financial officer, and effected by the board of directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the financial statements for external reporting purposes in accordance with generally accepted accounting principles.
Our internal control over financial reporting includes policies and procedures that:
• | pertain to the maintenance of records that in reasonable detail accurately and fairly reflect transactions of the Company; |
• | provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles; and |
• | provide reasonable assurance regarding prevention or timely detection of unauthorized transactions. |
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluations of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with our policies or procedures may deteriorate.
Management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2018, with the participation of our principal executive and principal financial officers, based on the framework established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, or COSO. Based on this assessment, management concluded that the Company maintained effective internal control over financial reporting as of December 31, 2018.
Attestation Report of the Registered Public Accounting Firm
Our independent registered public accounting firm will not be required to formally attest to the effectiveness of our internal controls over financial reporting for as long as we are an “emerging growth company” pursuant to the provisions of the JOBS Act.
Changes in Internal Control over Financial Reporting
In our annual report for the year ended December 31, 2017, we identified and disclosed material weaknesses related to non-routine and/or complex accounting transactions, which was attributable to the lack of sufficient qualified accounting personnel. To remediate the material weakness, we have we recruited technical, financial and accounting personnel and have made significant advancements to our internal controls surrounding non-routine and complex arrangements to strengthen our financial reporting processes since the Offering in August of 2017. Based on testing performed by management, we believe the implemented controls are operating effectively and the prior year material weakness has been remediated as of December 31, 2018. There were no other changes in our internal control over financial reporting during the year ended December 31, 2018 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
Item 9B. Other Information
Not applicable.
54
PART III
Item 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Please see the information appearing in the proposal for the election of directors and under the headings “Executive Officers,” “Information Concerning Meetings and Committees of the Board of Directors,” “Code of Business Conduct and Ethics and Corporate Governance Guidelines” and “Section 16(a) Beneficial Ownership Reporting Compliance” in the definitive proxy statement for our 2019 Annual Meeting of Shareholders for the information this Item 10 requires that is incorporated herein by reference.
Item 11. Executive Compensation
Please see the information appearing under the headings “Compensation Discussion and Analysis,” “Director Compensation,” “Executive Compensation,” “Compensation Committee Interlocks and Insider Participation” and “Report of the Compensation Committee” in the definitive proxy statement for our 2019 Annual Meeting of Shareholders for the information this Item 11 requires that is incorporated herein by reference.
Item 12. Security Ownership of Certain Beneficial Owners and Management Related Stockholder Matters
Please see the information appearing under the heading “Security Ownership of Certain Beneficial Owners and Management” in the definitive proxy statement for our 2019 Annual Meeting of Shareholders for the information this Item 12 requires that is incorporated herein by reference.
Item 13. Certain Relationships and Related Transactions and Director Independence
Please see the information appearing in the proposal for the election of directors and under the heading “Certain Relationships and Related Transactions” in the definitive proxy statement for our 2019 Annual Meeting of Shareholders for the information this Item 13 requires that is incorporated herein by reference.
Item 14. Principal Accounting Fees and Services
Please see the information appearing in the proposal for the ratification of the appointment of our independent registered public accounting firm in the definitive proxy statement for our 2019 Annual Meeting of Shareholders for the information this Item 14 requires that is incorporated herein by reference.
55
PART IV
Item 15. Exhibits, Financial Statement Schedules
(1) | Financial Statements. |
See index to Consolidated Financial Statements included beginning on Page F-1.
(2) | Financial Statement Schedules. |
No other financial statement schedules are submitted because either they are inapplicable or because the required information is included in the consolidated financial statements or notes thereto.
Exhibits.
The exhibits listed on the accompanying Exhibit Index are filed, furnished or incorporated by reference as part of this Annual Report, and such Exhibit Index is incorporated herein by reference.
Exhibit Number | Description | ||
2.1†† | |||
2.2†† | |||
2.3†† | |||
3.1 | |||
3.2 | |||
4.1 | |||
4.2 | |||
10.1 | |||
10.2† | |||
10.3† | |||
10.4† | |||
10.5 | |||
10.6 | |||
56
10.7‡ | |||
10.8† | |||
10.9† | |||
10.10† | |||
10.11† | |||
10.12† | |||
10.13† | |||
10.14† | |||
10.15† | |||
10.16† | |||
10.17† | |||
10.18† | |||
10.19† | |||
10.20 | |||
10.21 | |||
10.22 | |||
10.23 | |||
10.24 | |||
10.25 | |||
10.26 | |||
10.27 | |||
10.28 | |||
*21.1 | |||
*23.1 | |||
*31.1 | |||
*31.2 | |||
**32.1 | |||
57
**32.2 | |||
*101.CAL | XBRL Calculation Linkbase Document | ||
*101.DEF | XBRL Definition Linkbase Document | ||
*101.INS | XBRL Instance Document | ||
*101.LAB | XBRL Labels Linkbase Document | ||
*101.PRE | XBRL Presentation Linkbase Document | ||
*101.SCH | XBRL Schema Document | ||
* | Filed as an exhibit to this Annual Report on Form 10-K | |
** | Furnished as an exhibit to this Annual Report on Form 10-K | |
† | Compensatory plan or arrangement | |
†† | Schedules and similar attachments have been omitted pursuant to Item 601(b)(2) of Regulation S-K. The registrant will furnish a supplemental copy of any omitted schedule or similar attachment to the SEC upon request. | |
‡ | Confidential treatment was granted with respect to certain portions of this exhibit. Omitted portions filed separately with the SEC. | |
58
Item 16. Form 10-K Summary
None.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this Annual Report to be signed on its behalf by the undersigned, thereunto duly authorized.
Ranger Energy Services, Inc. | ||
/s/ Darron M. Anderson | March 6, 2019 | |
Darron M. Anderson | Date | |
President, Chief Executive Officer and Director | ||
(Principal Executive Officer) | ||
Pursuant to the requirements of the Securities Exchange Act of 1934, this Annual Report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
Signature | Title | Date | ||
/s/ Darron M. Anderson | President, Chief Executive Officer and Director | March 6, 2019 | ||
Darron M Anderson | (Principal Executive Officer) | |||
/s/ J. Brandon Blossman | Chief Financial Officer | March 6, 2019 | ||
J. Brandon Blossman | (Principal Financial Officer) | |||
/s/ Mario H. Hernandez | Chief Accounting Officer | March 6, 2019 | ||
Mario H. Hernandez | (Principal Accounting Officer) | |||
/s/ Merrill A. Miller Jr. | Chairman of the Board | March 6, 2019 | ||
Merrill A. Miller Jr. | ||||
/s/ William M. Austin | Director | March 6, 2019 | ||
William M. Austin | ||||
/s/ Brett Agee | Director | March 6, 2019 | ||
Brett Agee | ||||
/s/ Richard Agee | Director | March 6, 2019 | ||
Richard Agee | ||||
/s/ Krishna Shivram | Director | March 6, 2019 | ||
Krishna Shivram | ||||
/s/ Charles S. Leykum | Director | March 6, 2019 | ||
Charles S. Leykum | ||||
/s/ Gerald Cimador | Director | March 6, 2019 | ||
Gerald Cimador | ||||
/s/ Michael C. Kearney | Director | March 6, 2019 | ||
Michael C. Kearney | ||||
59
RANGER ENERGY SERVICES, INC.
INDEX TO FINANCIAL STATEMENTS
Page | ||
60
Report of Independent Registered Public Accounting Firm
To the Board of Directors and the Shareholders of
Ranger Energy Services, Inc.
Opinion on the Consolidated Financial Statements
We have audited the accompanying consolidated balance sheets of Ranger Energy Services, Inc. and its subsidiaries (collectively, the “Company”) as of December 31, 2018 and 2017, and the related consolidated statements of operations, equity, and cash flows for the years then ended and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company and subsidiaries as of December 31, 2018 and 2017, and the results of their operations and their cash flows for the years then ended December 31, 2018, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform an audit of internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal controls over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits and the report of the other auditors provide a reasonable basis for our opinion.
/s/ BDO USA, LLP
We have served as the Company's auditor since 2016.
Houston, Texas
March 6, 2019
F-1
RANGER ENERGY SERVICES, INC.
CONSOLIDATED BALANCE SHEETS
(in millions, except share and per share amounts)
December 31, | ||||||||
2018 | 2017 | |||||||
Assets | ||||||||
Cash and cash equivalents | $ | 2.6 | $ | 5.3 | ||||
Accounts receivable, net | 45.4 | 32.1 | ||||||
Contract assets | 3.1 | 6.0 | ||||||
Prepaid expenses | 5.1 | 4.2 | ||||||
Inventory | 4.9 | 1.5 | ||||||
Total current assets | 61.1 | 49.1 | ||||||
Property, plant and equipment, net | 229.8 | 189.2 | ||||||
Goodwill | — | 9.0 | ||||||
Intangible assets, net | 10.0 | 10.8 | ||||||
Other assets | 1.6 | 1.6 | ||||||
Total assets | $ | 302.5 | $ | 259.7 | ||||
Liabilities and Stockholders' Equity | ||||||||
Accounts payable | $ | 17.2 | $ | 32.0 | ||||
Accrued expenses | 18.5 | 11.6 | ||||||
Current maturities of capital lease obligations | 4.4 | 8.0 | ||||||
Current maturities of long-term debt | 15.8 | 1.3 | ||||||
Other current liabilities | 3.0 | — | ||||||
Total current liabilities | 58.9 | 52.9 | ||||||
Long-term capital lease obligations | 6.6 | 1.5 | ||||||
Long-term debt | 44.7 | 5.8 | ||||||
Other long-term liabilities | 0.3 | 3.8 | ||||||
Total liabilities | 110.5 | 64.0 | ||||||
Commitments and contingencies (Note 13) | ||||||||
Preferred stock, $0.01 per share; 50,000,000 shares authorized, no shares issued or outstanding as of December 31, 2018 and 2017 | — | — | ||||||
Class A Common Stock, $0.01 par value, 100,000,000 shares authorized; 8,448,527 shares and 8,413,178 shares issued and outstanding as of December 31, 2018 and 2017 , respectively | 0.1 | 0.1 | ||||||
Class B Common Stock, $0.01 par value, 100,000,000 shares authorized; 6,866,154 shares issued and outstanding at both December 31, 2018 and 2017 | 0.1 | 0.1 | ||||||
Accumulated deficit | (9.9 | ) | (6.6 | ) | ||||
Additional paid-in capital | 111.6 | 110.1 | ||||||
Total stockholders' equity | 101.9 | 103.7 | ||||||
Non-controlling interest | 90.1 | 92.0 | ||||||
Total stockholders' equity | 192.0 | 195.7 | ||||||
Total liabilities and stockholders' equity | $ | 302.5 | $ | 259.7 | ||||
The accompanying notes are an integral part of these consolidated financial statements.
F-2
RANGER ENERGY SERVICES, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
(in millions, except share and per share amounts)
Years Ended December 31, | ||||||||
2018 | 2017 | |||||||
Revenues | ||||||||
High specification rigs | $ | 149.9 | $ | 108.3 | ||||
Completion and other services | 136.0 | 37.4 | ||||||
Processing solutions | 17.2 | 8.3 | ||||||
Total revenues | 303.1 | 154.0 | ||||||
Operating expenses | ||||||||
Cost of services (exclusive of depreciation and amortization) | ||||||||
High specification rigs | 128.7 | 93.4 | ||||||
Completion and other services | 100.2 | 29.8 | ||||||
Processing solutions | 8.0 | 3.2 | ||||||
Total cost of services | 236.9 | 126.4 | ||||||
General and administrative | 29.0 | 30.4 | ||||||
Depreciation and amortization | 30.3 | 17.8 | ||||||
Impairment of goodwill | 9.0 | — | ||||||
Total operating expenses | 305.2 | 174.6 | ||||||
Operating loss | (2.1 | ) | (20.6 | ) | ||||
Other expenses | ||||||||
Interest expense, net | (3.7 | ) | (6.3 | ) | ||||
Total other expenses | (3.7 | ) | (6.3 | ) | ||||
Loss before income tax expense | (5.8 | ) | (26.9 | ) | ||||
Tax expense | — | 0.4 | ||||||
Net loss | (5.8 | ) | (27.3 | ) | ||||
Less: Net loss attributable to the Predecessor | — | (15.2 | ) | |||||
Less: Net loss attributable to non-controlling interests | (2.5 | ) | (5.5 | ) | ||||
Net loss attributable to Ranger Energy Services, Inc. | $ | (3.3 | ) | $ | (6.6 | ) | ||
Loss per common share | ||||||||
Basic | $ | (0.39 | ) | $ | (0.78 | ) | ||
Diluted | $ | (0.39 | ) | $ | (0.78 | ) | ||
Weighted average common shares outstanding | ||||||||
Basic | 8,425,593 | 8,413,178 | ||||||
Diluted | 8,425,593 | 8,413,178 | ||||||
The accompanying notes are an integral part of these consolidated financial statements.
F-3
RANGER ENERGY SERVICES, INC.
CONSOLIDATED STATEMENT OF EQUITY
(in millions, except shares)
Class A | Class B | Additional Paid-in Capital | Accumulated Deficit | Total Stockholders' Equity | Non Controlling Interests | Net Parent Investment | Total Equity | |||||||||||||||||||||||||||||||
Shares | Value | Shares | Value | |||||||||||||||||||||||||||||||||||
Balance at January 1, 2017 | — | — | — | — | — | — | — | — | 112.6 | 112.6 | ||||||||||||||||||||||||||||
Net contributions from parent | — | — | — | — | — | — | — | — | 4.0 | 4.0 | ||||||||||||||||||||||||||||
Equity based compensation from parent | — | — | — | — | — | — | — | 0.4 | 0.8 | 1.2 | ||||||||||||||||||||||||||||
Net loss | — | — | — | — | — | (6.6 | ) | (6.6 | ) | (5.5 | ) | (15.2 | ) | (27.3 | ) | |||||||||||||||||||||||
Effects of the Offering: | ||||||||||||||||||||||||||||||||||||||
Proceeds from shares sold to public | 5,112,069 | 0.1 | — | — | 74.1 | — | 74.2 | — | — | 74.2 | ||||||||||||||||||||||||||||
Underwriters fees and discounts | — | — | — | — | (4.2 | ) | — | (4.2 | ) | — | — | (4.2 | ) | |||||||||||||||||||||||||
Proceeds from shares sold to related parties | 750,000 | — | — | — | 10.9 | — | 10.9 | — | — | 10.9 | ||||||||||||||||||||||||||||
Costs of the Offering | — | — | — | — | (3.9 | ) | — | (3.9 | ) | — | — | (3.9 | ) | |||||||||||||||||||||||||
Obligation to related party | — | — | — | — | (3.0 | ) | — | (3.0 | ) | — | — | (3.0 | ) | |||||||||||||||||||||||||
Reorganization | 1,638,386 | — | 5,621,491 | 0.1 | 23.0 | — | 23.1 | 79.1 | (102.2 | ) | — | |||||||||||||||||||||||||||
Shares issued for acquisition of ESCO | 344,828 | — | — | — | 5.0 | — | 5.0 | — | — | 5.0 | ||||||||||||||||||||||||||||
Shares issued to pay for related party debt | 567,895 | — | 1,244,663 | — | 8.2 | — | 8.2 | 18.0 | — | 26.2 | ||||||||||||||||||||||||||||
Balance at December 31, 2017 | 8,413,178 | 0.1 | 6,866,154 | 0.1 | 110.1 | (6.6 | ) | 103.7 | 92.0 | — | 195.7 | |||||||||||||||||||||||||||
Equity based compensation | 35,349 | — | — | — | 1.5 | — | 1.5 | 0.6 | — | 2.1 | ||||||||||||||||||||||||||||
Net loss | — | — | — | — | — | (3.3 | ) | (3.3 | ) | (2.5 | ) | — | (5.8 | ) | ||||||||||||||||||||||||
Balance at December 31, 2018 | 8,448,527 | $ | 0.1 | 6,866,154 | $ | 0.1 | $ | 111.6 | $ | (9.9 | ) | $ | 101.9 | $ | 90.1 | $ | — | $ | 192.0 | |||||||||||||||||||
The accompanying notes are an integral part of these consolidated financial statements.
F-4
RANGER ENERGY SERVICES, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in millions)
Year ended December 31, | ||||||||
2018 | 2017 | |||||||
Cash Flows from Operating Activities | ||||||||
Net loss | $ | (5.8 | ) | $ | (27.3 | ) | ||
Adjustments to reconcile net loss to net cash provided by (used in) operating activities: | ||||||||
Depreciation and amortization | 30.3 | 17.8 | ||||||
Bad debt expense | 0.2 | 0.3 | ||||||
Issuance of Class A and Class B Common Stock for settlement of interest on related party debt | — | 5.2 | ||||||
Equity based compensation | 2.1 | 1.2 | ||||||
Impairment of goodwill | 9.0 | — | ||||||
Other costs, net | 0.2 | — | ||||||
Changes in operating assets and liabilities, net of effect of acquisitions | ||||||||
Accounts receivable | (13.5 | ) | (12.4 | ) | ||||
Contract assets | 2.9 | (4.7 | ) | |||||
Prepaid expenses | (0.9 | ) | (4.0 | ) | ||||
Inventory | (3.4 | ) | — | |||||
Other assets | (0.1 | ) | (0.7 | ) | ||||
Accounts payable | 0.2 | 2.6 | ||||||
Accounts payable - related party | — | (2.4 | ) | |||||
Accrued expenses | 7.5 | 7.4 | ||||||
Other long-term liabilities | (1.1 | ) | (0.3 | ) | ||||
Net cash provided by (used in) operating activities | 27.6 | (17.3 | ) | |||||
Cash Flows from Investing Activities | ||||||||
Purchase of property, plant and equipment | (75.9 | ) | (21.7 | ) | ||||
Proceeds from sale of property, plant and equipment | 5.5 | 0.5 | ||||||
Acquisitions, net of cash received | (4.0 | ) | (47.7 | ) | ||||
Net cash used in investing activities | (74.4 | ) | (68.9 | ) | ||||
Cash Flows from Financing Activities | ||||||||
Borrowings under line of credit | 56.0 | — | ||||||
Borrowings on ENCINA Master Financing Agreement, net of deferred financing costs | 39.1 | 0.1 | ||||||
Payments on line of credit facility | (37.6 | ) | (12.0 | ) | ||||
Payments on ENCINA Master Financing Agreement | (2.5 | ) | — | |||||
Payments on ESCO notes payable | (1.3 | ) | — | |||||
Payments on capital lease obligations | (9.6 | ) | (1.9 | ) | ||||
Proceeds from the Offering, net of underwriters' expense | — | 80.8 | ||||||
Borrowings on related party debt | — | 21.0 | ||||||
Payments incurred for the Offering | — | (3.9 | ) | |||||
Contributions from parent | — | 4.0 | ||||||
Net cash provided by financing activities | 44.1 | 88.1 | ||||||
Increase (decrease) in Cash and Cash equivalents, net | (2.7 | ) | 1.9 | |||||
Cash and Cash Equivalents, Beginning of Year | 5.3 | 3.4 | ||||||
Cash and Cash Equivalents, End of Year | $ | 2.6 | $ | 5.3 | ||||
Supplemental Cash Flows Information | ||||||||
Interest paid | $ | 2.1 | $ | 0.5 | ||||
Supplemental Disclosure of Non-cash Investing and Financing Activity | ||||||||
Non-cash capital expenditures | $ | 15.5 | $ | (24.5 | ) | |||
Non-cash additions to fixed assets through capital lease financing | $ | (11.1 | ) | $ | (10.7 | ) | ||
Issuance of Class A and Class B Common Stock for payment of related party debt | $ | — | $ | (21.0 | ) | |||
Issuance of Class A Common Stock for acquisition | $ | — | $ | (5.0 | ) | |||
Long-term obligation to related party | $ | — | $ | (3.0 | ) | |||
Seller's Notes for payment for acquisition | $ | — | $ | (7.0 | ) | |||
The accompanying notes are an integral part of these consolidated financial statements.
F-5
RANGER ENERGY SERVICES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1 — Organization and Business Operations
Organization
Ranger Energy Services, LLC (“Ranger Services”) was, through Ranger Energy Holdings, LLC (“Ranger Holdings”), formed by CSL Capital Management, LLC (“CSL”) in June 2014 as a provider of high‑spec well service rigs and associated services. Torrent Energy Services, LLC (“Torrent Services” and together with Ranger Services, the “Predecessor Company”) was, through Torrent Energy Holdings, LLC (“Torrent Holdings”), acquired by CSL in September 2014 as a provider of proprietary, modular equipment for the processing of natural gas. In June 2016, CSL indirectly acquired substantially all of the assets of Magna Energy Services, LLC (“Magna”), a provider of well services and wireline services, which it contributed to Ranger Services in September 2016. In October 2016, Ranger Services acquired substantially all of the assets of Bayou Workover Services, LLC (“Bayou”), an owner and operator of high‑spec well service rigs. These consolidated financial statements included in this Annual Report (i) prior to August 16, 2017 include, the historical financial information of Ranger Services, Torrent Services, Magna and Bayou (collectively, our “Predecessor”), 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 information of Ranger Energy Services, Inc. (“Ranger” or the “Company”).
Ranger was incorporated as a Delaware corporation in February 2017. In conjunction with Ranger’s initial public offering (the “Offering”) of Class A Common Stock, par value $0.01 per share (“Class A Common Stock”), which closed on August 16, 2017 and the corporate reorganization described below, Ranger is a holding company, the sole material assets of which consist of membership interests in RNGR Energy Services, LLC a Delaware limited liability company (“Ranger LLC”). Ranger LLC owns all of the outstanding equity interests in Ranger Services and Torrent Services, the subsidiaries through which it operates its assets. Through 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.
Reorganization
On August 10, 2017, Ranger Services, entered into a Master Reorganization Agreement (the “Master Reorganization Agreement”) with, among others, Ranger LLC, Ranger Holdings, Ranger Energy Holdings II, LLC, a Delaware limited liability company (“Ranger Holdings II”), Torrent Holdings, and Torrent Energy Holdings II, LLC, a Delaware limited liability company (“Torrent Holdings II” and, together with Ranger Holdings, Ranger Holdings II and Torrent Holdings, the “Existing Owners”).
Subject to the terms and conditions set forth in the Master Reorganization Agreement, the parties thereto effected a series of restructuring transactions in connection with the Offering, as a result of which:
(i) Ranger Holdings II and Torrent Holdings II contributed certain of the equity interests in Predecessor Companies to the Company in exchange for an aggregate of 1,638,386 shares of Class A Common Stock and the Company contributed such equity interests to Ranger LLC in exchange for 1,638,386 units in Ranger LLC (“Ranger Units”). Additionally, an aggregate of $3.0 million will be paid by the Company to CSL Energy Holdings I, LLC, a Delaware limited liability company and CSL Energy Holdings II, LLC, a Delaware limited liability company, on or prior to the 18-month anniversary of the consummation of the Offering in, at the Company’s option, cash, shares of Class A Common Stock (with such shares to be valued based on the greater of the price of the Class A Common Stock in the Offering and a 30-day volume-weighted average price) or a combination thereof (included within Other current liabilities on the accompanying consolidated balance sheet as of December 31, 2018);
(ii) Ranger Holdings and Torrent Holdings contributed the remaining membership interests in the Predecessor Companies to Ranger LLC in exchange for 5,621,491 Ranger Units and 5,621,491 shares of the Company’s Class B Common Stock, par value $0.01 per share (“Class B Common Stock”), which the Company initially issued and contributed to Ranger LLC;
(iii) the Company contributed all of the net proceeds received by it in the Offering to Ranger LLC in exchange for 5,862,069 Ranger Units;
(iv) Ranger LLC distributed to each of Ranger Holdings and Torrent Holdings one share of Class B Common Stock received pursuant to (ii) above for each Ranger Unit such Existing Owner held; and
(v) as consideration for the termination of certain loan agreements, the Company issued 567,895 shares of Class A Common Stock (in connection with Ranger LLC which issued 567,895 Ranger Units to the Company) and Ranger LLC issued
F-6
an aggregate of 1,244,663 Ranger Units (and distributed a corresponding number of shares of Class B Common Stock) to the lenders thereof.
The foregoing transactions were undertaken in reliance on an exemption from the registration requirements of the Securities Act of 1933, as amended (the “Securities Act”), pursuant to Section 4(a)(2) thereof. As a result of these transactions, Ranger LLC became a subsidiary of the Company and the Predecessor Companies became wholly owned subsidiaries of Ranger LLC.
Initial Public Offering
On August 16, 2017, the Company completed the Offering of 5,862,069 shares of its Class A Common Stock. The gross proceeds of the Offering to the Company, based on a public offering price of $14.50 per share, were $85.0 million, which resulted in net proceeds to the Company of $80.8 million, after deducting $4.2 million of underwriting discounts and commissions. The Company received net proceeds of approximately $20.7 million after it paid off the remainder of its 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 Company’s Class A Common Stock has voting rights one vote per one share held on record for all matters to be voted upon by the shareholders. The Class A Common Stock is entitled to ratably receive dividends when and if declared by the board of directors. The Class A Common Stock upon dissolution, distribution of assets or other winding up is entitled to receive ratably the assets available for distribution to shareholders after payment of liability and liquidation preference of any outstanding shares of preferred stock.
The Company’s Class B Common Stock has voting rights one vote per one share held on record for all matters to be voted upon by the shareholders. The Class B Common Stock has no rights to receive dividends, liquidation rights or any other economic interests.
Business
The Company is one of the largest providers of high specification (“high‑spec”) well service rigs and associated services in the United States, with a focus on technically demanding unconventional horizontal well completion and production operations. Our high‑specification well service rigs facilitate operations throughout the lifecycle of a well, including (i) completion services, such as milling out composite plugs after the hydraulic fracturing process and the installation of downhole production equipment; (ii) workover, including retrieval and replacement of existing production tubing; (iii) well maintenance, including replacement of downhole artificial lift components; and (iv) decommissioning, such as plugging and abandonment operations. The Company also provides Completion and Other Services, which provides services necessary to bring and maintain a well on production and primarily includes (i) wireline perforating and pumpdown services and (ii) snubbing services often utilized in conjunction with our high-spec rigs to convey equipment in and out of a well during completion and workover activities. The Company provides rental equipment, including well control packages, hydraulic catwalks and other equipment that are often deployed with our well service rigs. In addition, the Company owns and operates a fleet of proprietary, modular natural gas processing equipment that processes rich natural gas streams at the wellhead or central gathering points. The Company has operations in most of the active oil and natural gas basins in the United States, including the Permian Basin, the Denver‑Julesburg Basin, the Bakken Shale, the Eagle Ford Shale, the Haynesville Shale, the Gulf Coast and the South Central Oklahoma Oil Province (“SCOOP”) and Sooner Trend Anadarko Basin Canadian and Kingfisher counties (“STACK”) plays.
Note 2 — Summary of Significant Accounting Policies
Basis of Presentation
The accompanying audited consolidated financial statements of the Company have been prepared in accordance with generally accepted accounting principles in the United States (“GAAP”) and pursuant to the rules and regulations of the U.S. Securities and Exchange Commission (“SEC”). In the opinion of management, all material adjustments, which are of a normal and recurring nature, necessary for the fair presentation of the financial results for all periods presented have been reflected. All intercompany balances and transactions have been eliminated.
Investments in which the Company exercises control are consolidated and the noncontrolling interests of such investments, which are not attributable directly or indirectly to the Company, are presented as a separate component of net income and equity in the accompanying consolidated financial statements. The Company has ownership interests in Ranger LLC, which is consolidated within the Company’s financial statements but is not wholly owned by the Company. Changes in the Company’s ownership interest in Ranger LLC while it retains its controlling interest are accounted for as equity transactions.
F-7
We have made certain reclassifications to our prior period operating revenue, cost of sales and general and administrative amounts due to the change in reportable segments whereby our High Specification Rig and Completion and Other Services segments were bifurcated from our legacy Well Services segment as a result of our fourth quarter operating segment changes. None of these reclassifications have an impact on our consolidated results of operations, cash flows or financial position.
Use of Estimates
The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the reporting period. Management uses historical and other pertinent information to determine these estimates. Actual results could differ from such estimates. Areas where critical accounting estimates are made by management include:
• | Depreciation and amortization of property, plant and equipment and intangible assets; |
• | Impairment of property, plant and equipment, goodwill and intangible assets; |
• | Allowance for doubtful accounts; |
• | Fair value of assets acquired and liabilities assumed in an acquisition; and |
• | Equity‑based compensation. |
Significant Accounting Policies
Cash and Cash Equivalents
All highly liquid investments with an original maturity of three months or less are considered cash equivalents. The Company maintains its cash accounts in financial institutions that are insured by the Federal Deposit Insurance Corporation. Cash balances from time to time may exceed the insured amounts; however the Company has not experienced any losses in such accounts and does not believe it is exposed to any significant credit risks on such accounts.
Accounts Receivable
Accounts receivable, net are stated at the amount management expects to collect from outstanding balances. The Company reviews a customer’s credit history before extending credit. Generally, the Company does not require collateral from its customers. The allowance for doubtful accounts is established as losses are estimated to have occurred through a provision for bad debts charged to earnings. Losses are charged against the allowance when management believes the uncollectibility of a receivable is confirmed. Subsequent recoveries, if any, are credited to the allowance. The allowance for doubtful accounts is evaluated on a regular basis by management and based on past experience and other factors, which, in management’s judgment, deserve current recognition in estimating possible bad debts. Such factors include growth and composition of accounts receivable, the relationship of the allowance for doubtful accounts to accounts receivable and current economic conditions. The allowance for doubtful accounts was $0.5 million and $1.3 million for the years ended December 31, 2018 and 2017, respectively. Bad debt expense recorded for the years ended December 31, 2018 and 2017 was $0.2 million and $0.3 million, respectively.
Balance at Beginning of Year | Charged to Operations | Written Off | Balance at End of Year | |||||||||||||
Allowance for Doubtful Accounts Receivable | ||||||||||||||||
2018 | $ | 1.3 | $ | 0.2 | $ | (1.0 | ) | $ | 0.5 | |||||||
2017 | $ | 1.1 | $ | 0.3 | $ | (0.1 | ) | $ | 1.3 | |||||||
Inventories
Inventories are carried at the lower of cost or net realizable value and primarily consist of explosives used in completion and other services.
F-8
Property, Plant and Equipment
Property, plant and equipment is stated at cost or estimated fair market value at the acquisition date less accumulated depreciation. Depreciation is charged to expense on the straight‑line basis over the estimated useful life of each asset. Expenditures for major renewals and betterments are capitalized while expenditures for maintenance and repairs are charged to expenses as incurred. Assets under capital lease obligations and leasehold improvements are amortized over the shorter of the lease term or their respective estimated useful lives. Depreciation does not begin until property, plant and equipment is placed in service. Once placed in service, depreciation on property and equipment continues while being repaired, refurbished or between periods of deployment.
Long‑lived Asset Impairment
The Company evaluates the recoverability of the carrying value of long‑lived assets, including property, plant and equipment and intangible assets, whenever events or circumstances indicate the carrying amount may not be recoverable. If a long‑lived asset is tested for recoverability and the undiscounted estimated future cash flows expected to result from the use and eventual disposition of the asset is less than the carrying amount of the asset, the asset cost is adjusted to fair value and an impairment loss is recognized as the amount by which the carrying amount of a long‑lived asset exceeds its fair value.
Goodwill
Goodwill represents the excess of costs over the fair value of the net assets acquired in connection with a business combination. Goodwill is not amortized, but rather tested and assessed for impairment annually or more frequently if certain events or changes in circumstance indicate the carrying amount may exceed fair value. Before employing detailed impairment testing methodologies, the Company may first evaluate the likelihood of impairment by considering qualitative factors relevant to each reporting unit, such as macroeconomic, industry, market or any other factors that have a significant bearing on fair value. If the Company first utilizes a qualitative approach and determines that it is more likely than not that goodwill is impaired, detailed testing methodologies are then applied. Otherwise, the Company concludes that no impairment has occurred. Detailed impairment testing involves comparing the fair value of each reporting unit to its carrying value to determine whether an indication of impairment exists. If impairment is indicated, the Company will recognize an impairment loss for the amount by which the carrying amount of a reporting unit exceeds the reporting unit's fair value. However, the loss recognized cannot exceed the total amount of goodwill allocated to that reporting unit. The fair value of the reporting unit is typically determined through the use of a blended income and market approach. The Company recognized an impairment of $9.0 million during the year ended December 31, 2018, however did not recognize any impairments during the year ended December 31, 2017.
Intangible Assets
Identified intangible assets with determinable lives consist of customer relationships and trade names, as described in Note 5 — Goodwill and Intangible Assets. Customer relationships and trade names are amortized over their estimated useful lives.
Fair Value
Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants. The three‑tiered hierarchy is summarized as follows:
Level 1—Quoted prices in active markets for identical assets and liabilities.
Level 2—Other significant observable inputs.
Level 3—Significant unobservable inputs.
The Company’s financial instruments consist of cash and cash equivalents, trade receivables, trade payables, amounts receivable or payable to related parties, and long‑term debt. The carrying amount of cash and cash equivalents, trade receivables, and trade payables approximates fair value because of the short‑term nature of the instruments. The fair value of long‑term debt approximates its carrying value based on the borrowing rates currently available to the Company for bank loans with similar terms and maturities. In valuing certain assets and liabilities, the inputs used to measure fair value may fall into different levels of the fair value hierarchy. For disclosure purposes, assets and liabilities are classified in the fair value hierarchy based on the lowest level of input that is significant to the overall fair value. The Company did not have any assets or liabilities that were measured at fair value on a recurring basis at December 31, 2018 and 2017.
During 2017, the Company had non‑recurring fair value measurements related to the acquisition and purchase price allocations of ESCO (see Note 4 — Property and Equipment) and during 2018 had non-recurring fair value measurements related
F-9
to the impairment of goodwill. The fair values were determined through the use of a blended income, market and cost approach, which represent Level 3 measurements within the fair value hierarchy.
Revenue Recognition
Effective January 1, 2018, the Company adopted Accounting Standards Codification (“ASC”) Revenue from Contracts with Customers (“ASC 606”), using the modified retrospective method. This standard applies to all contracts with customers, except for contracts that are within the scope of other standards, such as leases, insurance, collaborative arrangements and financial instruments. Under ASC 606, an entity recognizes revenue when it transfers control of the promised goods or services to its customer, in an amount that reflects the consideration which the entity expects to receive in exchange for those goods or services. If control transfers to the customer over time, an entity selects a method to measure progress that is consistent with the objective of depicting its performance. The provisions of ASC 606 were applied to contracts not completed at January 1, 2018. There was no impact upon adoption of ASC 606. As a result, no disclosure of the impact for each financial statement line items is applicable.
In determining the appropriate amount of revenue to be recognized as the Company fulfills the obligations under its contracts with customers, the following steps must be performed at contract inception: (i) identification of the promised goods or services in the contract; (ii) determination of whether the promised goods or services are performance obligations, including whether they are distinct in the context of the contract; (iii) measurement of the transaction price, including the constraint on variable consideration; (iv) allocation of the transaction price to the performance obligations and (v) recognition of revenue when (or as) the Company satisfies each performance obligation.
The Company conducts its business through three segments: High Specification Rigs, Completion and Other Services and Processing Solutions. The High Specification Rig segment consists primarily of completion, maintenance, workover and plugging and abandonment services. The Completion and Other Services segment provides other necessary services to bring and maintain a well on production. The Processing Solutions segment consists primarily of equipment rentals and services related to operations, maintenance and mobilization. The services of each segment are based on mutually agreed upon pricing with the customer prior to the services being performed, and given the nature of the services, do not include any warranty and right of return. Pricing for these services are by the hour or by the day, when services are performed and are based on the nature of the specific job, with consideration for the extent of equipment, labor, and consumables needed for the job. Accordingly, the hourly and daily pricing is considered to be variable consideration. Pricing for equipment rentals is based on fixed monthly service fees. For more information on the Company's segments, see Note 15 — Segment Reporting.
We satisfy our performance obligation over time as the services are performed. The Company believes the output method is a reasonable measure of progress for the satisfaction of our performance obligations, which are satisfied over time, as it provides a faithful depiction of (1) our performance toward complete satisfaction of the performance obligation under the contract and (2) the value transferred to the customer of the services performed under the contract. The Company has elected the right to invoice practical expedient for recognizing revenue. The Company invoices customers upon completion of the specified services and collection generally occurs within the payment terms agreed with customers. Accordingly, there is no financing component to our arrangements with customers.
Taxes assessed on High Specification Rigs, Completions and Other Services and Processing Solutions revenue transactions are presented on a net basis included within the consolidated statements of operations and therefore are excluded from revenues.
Disaggregated Revenue
The following table summarizes our disaggregated revenues for the years ended December 31, 2018 and 2017 (in millions):
Year Ended December 31, | ||||||||
2018 | 2017 | |||||||
High Specification Rig revenue | 149.9 | 108.3 | ||||||
Completion and Other Services revenue | 136.0 | 37.4 | ||||||
Processing Solutions revenue | 17.2 | 8.3 | ||||||
Total Revenue | $ | 303.1 | $ | 154.0 | ||||
Contract Balances
Contract assets representing the Company’s rights to consideration for work completed but not billed amounted to $3.1 million and $6.0 million as of December 31, 2018 and 2017, respectively. Substantially all of the contract assets as of December 31, 2018 and 2017 were invoiced during the subsequent periods.
F-10
The Company does not have any contract liabilities included in the consolidated balance sheet as of December 31, 2018 and 2017.
Business Combinations
The Company recognizes, separately from goodwill, the identifiable assets acquired and liabilities assumed at their estimated acquisition date fair values. Fair value is the price that would be received to sell an asset or would be paid to transfer a liability in an orderly transaction between market participants at the measurement date. The fair value measurement is based on the assumptions of market participants and not those of the reporting entity. Therefore, entity‑specific intentions do not impact the measurement of fair value. Goodwill as of the acquisition date is measured and recognized as the excess of: (i) the aggregate of the fair value of the consideration transferred, the fair value of any non‑controlling interest in the acquiree and the acquisition date fair value of our previously held equity interests over (ii) the fair value of assets acquired and liabilities assumed. These fair values are accounted for at the date of acquisition and included in the consolidated balance sheets at December 31, 2017. There were no material business combinations that took place during the year ended December 31, 2018.The results of operations of an acquired business are included in the statements of operations from the date of the acquisition.
Income Taxes
The Company provides for income tax expense based on the liability method of accounting for income taxes based on the authoritative accounting guidance. Deferred tax assets and liabilities are recorded based upon differences between the tax basis of assets and liabilities and their carrying values for financial reporting purposes, and are measured using the enacted tax rates and laws that will be in effect when the differences are expected to reverse. A valuation allowance is established when it is more likely than not that some portion or all of the deferred tax assets will not be realized. The establishment of a valuation allowance requires significant judgment and is impacted by various estimates. Both positive and negative evidence, as well as the objectivity and verifiability of that evidence, is considered in determining the appropriateness of recording a valuation allowance on deferred tax assets. Under GAAP, the valuation allowance is recorded to reduce the Company's deferred tax assets to an amount that is more likely than not to be realized and is based upon the uncertainty of the realization of certain federal and state deferred tax assets related to net operating loss carryforwards and other tax attributes. The ultimate realization of the deferred tax assets depends on the generation of sufficient taxable income. Deferred tax expense or benefit is the result of changes in deferred tax assets and liabilities and associated valuation allowances during the period. The impact of an uncertain tax position taken or expected to be taken on an income tax return is recognized in the financial statements at the largest amount that is more likely than not to be sustained upon examination by the relevant taxing authority.
The income tax provision reflects the full benefit of all positions that have been taken in the Company's income tax returns, except to the extent that such positions are uncertain and fall below the recognition requirements. In the event that the Company determines that a tax position meets the uncertainty criteria, an additional liability or benefit will result. The amount of unrecognized tax benefit requires management to make significant assumptions about the expected outcomes of certain tax positions included in filed or yet to be filed tax returns. At December 31, 2018 and 2017, the Company did not have any uncertain tax positions. The Company is subject to income taxes in the United States and in numerous state tax jurisdictions. The Company's tax filing for December 31, 2017 is subject to audit by the federal and state taxing authorities in most jurisdictions where we conduct business. None of the Company's federal or state tax returns are currently under examination. These audits may result in assessments of additional taxes that are resolved with the authorities or through the courts.
The Company records income tax related interest and penalties, if applicable, as a component of tax expense. However, there were no such amounts recognized in the consolidated statements of operations in 2018 and 2017.
Equity-Based Compensation
The financial statements reflect various equity-based compensation awards granted by Ranger and the Predecessor. These awards include profits interest awards, restricted stock, stock options, restricted units and phantom units. The Company recognizes compensation expense related to equity-based awards granted based on the estimated fair value of the awards on the date of grant. The fair value of the equity-based awards on the grant date is generally recognized on a straight-line basis over the requisite service period, which is generally the vesting period of the respective awards.
Emerging Growth Company status
The Company is an “emerging growth company” as defined in the Jumpstart Our Business Startups Act of 2012 (the “JOBS Act”). The Company will remain an emerging growth company until the earlier of (1) the last day of its fiscal year (a) following the fifth anniversary of the completion of the Offering, (b) in which its total annual gross revenue is at least $1.07 billion, or (c) in which the Company is deemed to be a large accelerated filer, which means the market value of our common stock that
F-11
is held by non-affiliates exceeds $700.0 million as of the last business day of its most recently completed second fiscal quarter, or (2) the date on which the Company has issued more than $1.0 billion in non-convertible debt securities during the prior three-year period. An emerging growth company may take advantage of specified reduced reporting and other burdens that are otherwise applicable to public companies. The Company has irrevocably opted out of the extended transition period and, as a result, the Company will adopt new or revised accounting standards on the relevant dates on which adoption of such standards is required for other public companies.
Recent Accounting Pronouncements
Recently adopted accounting standards
In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accountant Standards Update (“ASU”) 2019-09, Revenue from Contracts with Customers, as amended by ASU 2015-14. ASU 2014-09 superseded the existing revenue recognition requirements in GAAP and requires an entity to recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled to in exchange for those good or services. Additionally, it requires expanded disclosures regarding the nature, amount, timing and certainty of revenue and cash flows from contracts with customers. Effective January 1, 2018, we adopted this accounting standard using the modified retrospective approach and there was no impact on our consolidated financial statements. See Note 2 — Summary of Significant Accounting Policies for additional information related to the adoption of this standard.
In August 2016, the FASB issued ASU 2016‑15, Statement of Cash Flows (Topic 230), Classification of Certain Cash Receipts and Cash Payments. ASU 2016‑15 reduces diversity in practice in how certain transactions are classified in the statement of cash flows. The guidance addresses specific cash flow issues for which current GAAP is either unclear or does not include specific guidance. ASU 2016‑15 is effective for annual and interim periods beginning after December 15, 2017. Effective January 1, 2018, we adopted this accounting standard and there was no material impact on the consolidated financial statements of cash flows.
In November 2016, the FASB issued ASU 2016-18, Statement of Cash Flows (Topic 230), Restricted Cash. ASU 2016-18 requires restricted cash and restricted cash equivalents be included with cash and cash equivalents when reconciling the beginning and end of period total amounts presented on the statement of cash flows. The Company adopted the new guidance on the effective date January 1, 2018 and noted no material impact on the consolidated financial statements of cash flows.
In January 2017, the FASB issued ASU 2017‑04, Intangibles—Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment. ASU 2017‑04 eliminates the requirement to calculate the implied fair value of goodwill to measure a goodwill impairment charge. Instead, entities will record an impairment charge based on the excess of a reporting unit’s carrying amount over its fair value. The ASU is effective for annual and interim impairment tests performed in periods beginning after December 15, 2019, and early adoption is permitted. The Company early adopted this guidance for its current annual and interim goodwill impairment testing as of January 1, 2018. The ASU impacted how the Company tests goodwill for impairment, as it eliminates the second step of the goodwill impairment test, thus effectively calculating impairment loss based on the difference between the carrying value and estimated fair value of the reporting units.
Recently issued accounting standards
In February 2016, the FASB issued ASU 2016‑02, Leases, amending the current accounting for leases. Under the new provisions, all lessees will report a right‑of‑use asset and a corresponding liability for the obligation to make payments for such leases, with the exception of those leases with a term of 12 months or less. All capitalized leases will fall into one of two categories: (i) financing lease or (ii) operating lease. Lessor accounting remains substantially unchanged with the exception that no leases entered into after the effective date will be classified as leveraged leases. Effective January 1, 2019, we will adopt ASU 2016‑02 using a modified retrospective approach. Our adoption, and ultimate effect on our consolidated financial statements, will be based on an evaluation of the contract-specific facts and circumstances. The Company has elected the package of practical expedients to not reassess prior conclusions related to contracts containing leases, lease classification and initial direct costs. In March 2018, the FASB approved a new, optional transition method that will give companies the option to use the effective date as the date of initial application on transitions. The Company is electing the optional transition method, and as a result, will not adjust its comparative period financial information or make the new required lease disclosures for periods prior to the effective date. The Company has elected to make the accounting policy election for short-term leases, therefore the lease payments will be recorded as an expense on a straight line basis over the lease term. The Company has elected to combine lease and non-lease components and, however has elected to not utilize the hindsight expedient or the land easement practical expedient. Based on the lease arrangements under which we are the lessee as of December 31, 2018, we expect to recognize right-of-use assets and a corresponding lease liability between $8.0 million and $9.0 million.
F-12
With the exception of the standards above, there have been no new accounting pronouncements not yet effective that have significance, or potential significance, to the Company's consolidated financial statements.
Tax Reform
On December 22, 2017, the Tax Cuts and Jobs Act (“Tax Act”) was enacted into law. Among the significant changes made by the Act was the reduction of the federal income tax rate from 35% to 21%. US GAAP requires that the impact of the Tax Act be recognized in the period in which the law was enacted. During the year ended December 31, 2018, we recorded tax changes for the impact of the Tax Act effects using the current available information and technical guidance on the interpretations of the Tax Act. As permitted by SEC staff Accounting Bulletin 118, Income Tax Accounting Implications of the Tax Cuts and Jobs Act, we recorded provisional estimates and have subsequently finalized our accounting analysis based on the guidance, interpretations, and data available.
Note 3 — Acquisitions
ESCO Acquisition
In connection with the closing of our offering on August 16, 2017, the Company closed on the ESCO Acquisition for total consideration of $59.7 million, consisting of $47.7 million in cash, $7.0 million in secured seller notes and $5.0 million in shares of Ranger’s Class A Common Stock based on the initial public offering price of $14.50 per share.
The ESCO Acquisition assets were primarily engaged in the completion, repair and workover of oil and gas wells for its customers. The ESCO Acquisition is being accounted for as a business combination. Goodwill is recorded in conjunction with the ESCO Acquisition as the total purchase consideration exceeds the approximated fair value of assets acquired and liabilities assumed.
The following information below represents the preliminary purchase allocation related to the ESCO Acquisition (in millions):
Purchase price | |||
Cash | $ | 47.7 | |
Seller's notes | 7.0 | ||
Equity issued | 5.0 | ||
Total purchase price | $ | 59.7 | |
Purchase price allocation | |||
Accounts receivable | $ | 6.6 | |
Property, plant and equipment | 45.9 | ||
Intangible assets | 2.2 | ||
Other assets | 0.3 | ||
Total assets acquired | 55.0 | ||
Accounts payable | (0.5 | ) | |
Accrued expenses | (2.2 | ) | |
Total liabilities assumed | (2.7 | ) | |
Goodwill | 7.4 | ||
Allocated purchase price | $ | 59.7 | |
Goodwill represents trained and assembled workforce which does not meet the separability criterion. The costs related to the transaction were $1.2 million and were expensed during 2017 in the Company's consolidated statements of operations for the year ended December 31, 2017.
F-13
The following is supplemental pro-forma revenue, operating loss, and net loss had the ESCO Acquisition occurred as of January 1, 2017 (in millions):
Year Ended December 31, | ||||||
2018 | 2017 | |||||
Supplemental Pro Forma: | ||||||
Revenue | 303.1 | 176.7 | ||||
Operating Loss | (2.1 | ) | (22.6 | ) | ||
Net Loss | (5.8 | ) | (29.5 | ) | ||
The supplemental pro forma revenue, operating loss, and net loss are presented for informational purposes only and may not necessarily reflect the future results of operations of the Company or what the results of operations would have been had the Company owned and operated the ESCO Acquisition assets since January 1, 2017. There are no material non-recurring adjustments included in these supplemental pro forma items.
We reported revenue for the years ended December 31, 2018 and 2017 that included $31.6 million and $14.1 million, respectively, generated from the rig assets acquired in connection with the ESCO Acquisition.
MVCI Acquisition
On January 31, 2018, the Company closed on the acquisition of MVCI Energy Services (“MVCI Acquisition”) for a total consideration of $4.0 million in cash. The MVCI Acquisition assets were primarily engaged in well testing services for its customers. The MVCI Acquisition is being accounted for as a business combination. The Company evaluated its purchase allocation and has reported $4.0 million on its consolidated balance sheets as property, plant and equipment. The pro forma results of operations for the MVCI Acquisition is not presented because the pro forma effects, individually and in the aggregate, are not material to the Company's consolidated results of operations.
Note 4 — Property and Equipment
Property, plant and equipment include the following (in millions):
Estimated Useful Life | December 31, | |||||||||
2018 | 2017 | |||||||||
Machinery and equipment | 5 - 30 | $ | 42.0 | $ | 17.6 | |||||
Vehicles | 3 - 5 | 17.9 | 7.9 | |||||||
Mechanical refrigeration units | 30 | 22.0 | 17.1 | |||||||
NGL storage tanks | 15 | 7.5 | 4.3 | |||||||
Workover rigs | 5 - 20 | 178.1 | 155.7 | |||||||
Other property, plant and equipment | 3 - 30 | 14.8 | 12.0 | |||||||
Property, plant and equipment | 282.3 | 214.6 | ||||||||
Less: accumulated depreciation | (52.5 | ) | (25.4 | ) | ||||||
Property, plant and equipment, net | $ | 229.8 | $ | 189.2 | ||||||
Depreciation expense was $29.5 million and $17.2 million for the years ended December 31, 2018 and 2017, respectively.
Note 5 — Goodwill and Intangible Assets
During the year ended December 31, 2018, the Company noted a sustained decrease in the stock price, which was an indication that the fair value of our goodwill could have fallen below its carrying amount. As a result, the Company performed a quantitative impairment test and determined the goodwill was impaired. We estimated the implied fair value of the goodwill using a variety of valuation methods, including the income and market approaches. During the year ended December 31, 2018, we recognized a loss of $9.0 million associated with the remaining balance of our goodwill. Our estimate of fair value required us to use significant unobservable inputs, representative of a Level 3 fair value measurement.
During the year ended December 31, 2017, in connection with the ESCO Acquisition we recognized $7.4 million of goodwill. The Company has $9.1 million of goodwill that is deductible for income tax purposes.
F-14
The gross carrying amounts and impairments associated with our goodwill were as follows (in millions):
Amount | |||
Balance, January 1, 2017 | $ | 1.6 | |
Acquired | 7.4 | ||
Impaired | — | ||
Balance, December 31, 2017 | 9.0 | ||
Acquired | — | ||
Impaired | 9.0 | ||
Balance, December 31, 2018 | $ | — | |
Definite lived intangible assets are comprised of the following (in millions):
Estimated Useful Life | December 31, | |||||||||
2018 | 2017 | |||||||||
Tradenames | 3 | $ | 0.1 | $ | 0.1 | |||||
Customer relationships | 10 - 18 | 11.4 | 11.4 | |||||||
Less: accumulated amortization | (1.5 | ) | (0.7 | ) | ||||||
Intangible assets, net | $ | 10.0 | $ | 10.8 | ||||||
Amortization expense was $0.8 million and $0.6 million for the years ended December 31, 2018 and 2017, respectively. Amortization expense for the future periods is expected to be as follows (in millions):
Year Ended December 31, | Amount | ||
2019 | $ | 0.8 | |
2020 | 0.7 | ||
2021 | 0.7 | ||
2022 | 0.7 | ||
2023 | 0.7 | ||
Thereafter | 6.4 | ||
Total | $ | 10.0 | |
Note 6 — Accrued Expenses
Accrued expenses include the following (in millions):
December 31, | ||||||||
2018 | 2017 | |||||||
Accrued payables | $ | 5.6 | $ | 4.8 | ||||
Accrued payroll | 6.2 | 2.9 | ||||||
Accrued taxes | 2.9 | 1.4 | ||||||
Accrued insurance | 3.8 | 2.5 | ||||||
Accrued expenses | $ | 18.5 | $ | 11.6 | ||||
Note 7 — Capital Leases
The Company leases certain assets under capital leases which expire at various dates through 2023. The assets and liabilities under capital leases are recorded at the lower of present value of the minimum lease payments or the fair value of the assets. The assets are amortized over the shorter of the estimated useful lives or over the lease term. Amortization expense of assets under capital leases was $3.0 million and $1.9 million for the years ended December 31, 2018 and 2017, respectively and included within Depreciation and Amortization on the consolidated Statements of Operations.
F-15
In February 2017, the Company entered into a lease agreement for certain high‑specification rig equipment for use in its business operations. The lease is being accounted for as a capital lease, as the present value of minimum monthly lease payments, including the purchase option, exceeds 90 percent of the fair value of the leased property at inception of the lease.
Aggregate future minimum lease payments under capital leases are as follows (in millions):
Year Ended December 31, | Total | ||
2019 | $ | 5.0 | |
2020 | 4.6 | ||
2021 | 2.1 | ||
2022 | 0.2 | ||
2023 | 0.1 | ||
Thereafter | — | ||
Total future minimum lease payments | 12.0 | ||
Less: amount representing interest | (1.0 | ) | |
Present value of future minimum lease payments | 11.0 | ||
Less: current portion of capital lease obligations | (4.4 | ) | |
Total capital lease obligations, less current portion | $ | 6.6 | |
Note 8 — Debt
The aggregate carrying amounts, net of issuance costs, of the Company's debt consists of the following (in millions):
December 31, | ||||||||
2018 | 2017 | |||||||
ESCO Note Payable due February 2019 | $ | 5.8 | $ | 7.0 | ||||
ENCINA Master Financing Agreement due June 2020 | 36.8 | — | ||||||
Wells Fargo Credit Facility | 17.9 | 0.1 | ||||||
Total debt | 60.5 | 7.1 | ||||||
Current portion of long-term debt | (15.8 | ) | (1.3 | ) | ||||
Long-term debt | $ | 44.7 | $ | 5.8 | ||||
ESCO Notes Payable
On August 16, 2017, in connection with the Offering and the ESCO Acquisition the Company issued $7.0 million of seller’s notes as partial consideration for the ESCO Acquisition. These notes included a note for $1.2 million, which was paid in August 2018 and a note for $5.8 million due in February 2019. The notes bear interest at 5.0% payable quarterly until their respective maturity dates.
During the year ended December 31, 2018, we provided notice to ESCO Leasing, LLC that we are seeking to be indemnified for breach of our contract. We exercised our right to stop payments of the remaining principal balance of $5.8 million on the Seller's Notes and any unpaid interest, pending resolution of certain indemnification claims.
Credit Facility
On August 16, 2017, in connection with the Offering, Ranger entered into a $50.0 million senior revolving credit facility (the “Credit Facility”) by and among certain of Ranger’s subsidiaries, as borrowers, each of the lenders party thereto and Wells Fargo Bank, N.A., as administrative agent (the “Administrative Agent”). The Credit Facility is subject to a borrowing base that is calculated based upon a percentage of the value of the Company's eligible accounts receivable less certain reserves.
The Credit Facility permits extensions of credit up to the lesser of $50.0 million and a borrowing base that is determined by calculating the amount equal to the sum of (i) 85% of the Eligible Accounts (as defined in the Credit Facility), less the amount, if any, of the Dilution Reserve (as defined in the Credit Facility), minus (ii) the aggregate amount of Reserves (as defined in the Credit Facility), if any, established by the Administrative Agent from time to time pursuant to the Credit Facility. The borrowing base is calculated on a monthly basis pursuant to a borrowing base certificate delivered by the Borrower to the Administrative Agent.
F-16
Borrowings under the Credit Facility bear interest, at the Company’s election, at either the (a) one-, two-, three- or six-month LIBOR or (b) the greatest of (i) the federal funds rate plus ½%, (ii) the one-month LIBOR plus 1% and (iii) the Administrative Agent’s prime rate (the “Base Rate”), in each case plus an applicable margin, and interest shall be payable monthly in arrears. The applicable margin for LIBOR loans ranges from 1.50% to 2.0% and the applicable margin for Base Rate loans ranges from 0.5% to 1.0%, in each case, depending on the Company’s average excess availability under the Credit Facility. The applicable margin for the LIBOR loan was 0.5% as of December 31, 2018. During the continuance of a bankruptcy event of default, automatically and during the continuance of any other default, upon the Administrative Agent’s or the required lenders’ election, all outstanding amounts under the Credit Facility bears interest at 2.0% plus the otherwise applicable interest rate. The Credit Facility is scheduled to mature on August 16, 2022.
In addition, the Credit Facility restricts the Company’s ability to make distributions on, or redeem or repurchase, our equity interests, except for certain distributions, including distributions of cash so long as, both at the time of the distribution and after giving effect to the distribution, no default exists under the Credit Facility and either (a) excess availability at all times during the preceding 90 consecutive days, on a pro forma basis and after giving effect to such distribution, is not less than the greater of (1) 22.5% of the lesser of (A) the maximum revolver amount and (B) the then-effective borrowing base and (2)$10.0 million or (b) if our fixed charge coverage ratio is at least 1.0x on a pro forma basis, excess availability at all times during the preceding 90 consecutive days, on a pro forma basis and after giving effect to such distribution, is not less than the greater of (1) 17.5% of the lesser of (A) the maximum revolver amount and (B) the then-effective borrowing base and (2)$7.0 million. If the foregoing threshold under clause (b) is met, the Company may not make such distributions (but may make certain other distributions, including under clause (a) above) prior to the earlier of the date that is (a) twelve (12) months from closing or (b) the date that the Company’s fixed charge coverage ratio is at least 1.0x for two consecutive quarters. The Credit Facility generally permits the Company to make distributions required under the Tax Receivable Agreement (as defined in Note 14 — Related Party Transactions), but a ‘‘Change of Control’’ under the Tax Receivable Agreement constitutes an event of default under the Credit Facility, and the Credit Facility does not permit the Company to make payments under the Tax Receivable Agreement upon acceleration of our obligations thereunder unless no event of default exists or would result therefrom and we have been in compliance with the fixed charge coverage ratio for the most recent 12-month period on a pro forma basis. The Credit Facility also requires the Company to maintain a fixed charge coverage ratio of at least 1.0x if the Company’s liquidity is less than $10.0 million until the Company’s liquidity is at least $10.0 million for thirty (30) consecutive days. The Company is not be subject to a fixed charge coverage ratio if it has no drawings under the Credit Facility and has at least $20.0 million of qualified cash.
The Credit Facility contains events of default customary for facilities of this nature, including, but not limited, to:
• | events of default resulting from our failure or the failure of any guarantors to comply with covenants and financial ratios; |
• | the occurrence of a change of control; |
• | the institution of insolvency or similar proceedings against the Company or any guarantor; and |
• | the occurrence of a default under any other material indebtedness the Company or any guarantor may have. |
Upon the occurrence and during the continuation of an event of default, subject to the terms and conditions of the Credit Facility, the lenders are able to declare any outstanding principal of the Credit Facility debt, together with accrued and unpaid interest, to be immediately due and payable and exercise other remedies.
As of December 31, 2018, under the Credit facility, the Company has borrowed $18.5 million, has a borrowing capacity of $36.2 million, with a residual $17.7 million available for borrowing. The Company is in compliance with the Credit Facility covenants as of December 31, 2018. As of December 31, 2018 the Credit Facility had an interest rate of 4.1%.
The Company capitalized fees of $0.7 million associated with the Credit Facility, which are included on the consolidated balance sheets as a discount to the Credit Facility and will be amortized through maturity. Unamortized debt issuance costs as of December 31, 2018 approximated $0.5 million.
Encina Master Financing and Security Agreement (“Financing Agreement”)
On June 22, 2018, the Company entered into a Financing Agreement with Encina Equipment Finance SPV, LLC (the “Lender”). The amount available to be provided by the Lender to the Company under the Financing Agreement was contemplated to be not less than $35.0 million, and not to exceed $40.0 million. The first financing was required to be in an amount up to $22.0 million, which was used by the Company to acquire certain capital equipment. Subsequent to the first financing, the Company borrowed an additional $17.8 million, net of expenses, under the Financing Agreement. We anticipate utilizing the additional net
F-17
proceeds to acquire certain capital equipment. The Financing Agreement is secured by a lien on certain high specification rig assets. As of December 31, 2018, the aggregate principal balance outstanding was $37.5 million under the Financing Agreement. Amounts outstanding under the Financing Agreement are payable ratably over 48 months through the maturity of July 2022.
Borrowings under the Financing Agreement bear interest at a rate per annum equal to the sum of 8.0% plus the London Interbank Offered Rate (“LIBOR”), which was 2.4% as of December 31, 2018. The Financing Agreement requires that the Company maintain leverage ratios of 3.50 to 1.00 as of December 31, 2018 and 2.50 to 1.00 for periods thereafter. The Company was in compliance with the covenants under the Financing Agreement as of December 31, 2018.
The Company capitalized fees of $0.9 million associated with the Financing Agreement, which are included on the Consolidated Balance Sheets as a discount to the long term debt and will be amortized through maturity. Unamortized debt issuance costs as of December 31, 2018 approximated $0.8 million.
Debt Obligations and Scheduled Maturities
As of December 31, 2018, aggregate principal repayments of total debt for the next five years are as follows (in millions):
Year Ended December 31, | Total | ||
2019 | $ | 15.7 | |
2020 | 10.0 | ||
2021 | 10.0 | ||
2022 | 26.0 | ||
2023 | 0.1 | ||
Total | $ | 61.8 | |
Note 9 — Equity Based Compensation
Long-term Incentive Plan
On August 10, 2017, the Board adopted the Ranger Energy Services, Inc. 2017 Long-Term Incentive Plan (“LTIP”) for the employees, consultants and the directors of the Company and its affiliates who perform services for the Company. The LTIP provides for potential grants of: (i) incentive stock options qualified as such under U.S. federal income tax laws; (ii) non-statutory stock options that do not qualify as incentive stock options; (iii) stock appreciation rights; (iv) restricted stock awards; (v) restricted stock units; (vi) bonus stock; (vii) performance awards; (viii) dividend equivalents; (ix) other stock-based awards; (x) cash awards; and (xi) substitute awards. Subject to adjustment in accordance with the terms of the LTIP, 1,250,000 shares of Class A Common Stock have been reserved for issuance pursuant to awards under the LTIP. Class A Common Stock withheld to satisfy exercise prices or tax withholding obligations will be available for delivery pursuant to other awards. The LTIP will be administered by the Board or an alternative committee appointed by the Board.
Time Based Restricted Stock
During the year ended December 31, 2018 there were 563,002 restricted shares issued. The aggregate value of awards granted during 2018 was $4.6 million, of which $1.3 million was amortized during the year ended December 31, 2018. As of December 31, 2018, there was $2.9 million of unrecognized expense.
The following table summarizes the changes in the restricted shares outstanding for the year ended December 31, 2018 and 2017:
F-18
Shares | Weighted Average Grant Date Fair Value | Weighted Average Remaining Vesting Period | ||||||||
Unvested as of January 1, 2017 | — | $ | — | — | ||||||
Granted | 10,000 | 9.43 | 1.9 years | |||||||
Forfeited | — | |||||||||
Unvested as of December 31, 2017 | 10,000 | |||||||||
Granted | 563,002 | 8.25 | 2.4 years | |||||||
Forfeited | (50,913 | ) | ||||||||
Vested | (40,379 | ) | ||||||||
Unvested as of December 31, 2018 | 481,710 | $ | 8.25 | 2.4 years | ||||||
Market Based Restricted Stock Units
During the year ended December 31, 2018, the Company granted 90,436 target shares of market based performance restricted stock units at a relative and absolute grant date fair value of $8.59 per share and $4.38 per share, respectively, to certain employees. The market based performance restricted stock units cliff vest on December 31, 2020. As defined in the LTIP, the performance criteria applicable to the performance awards is measured at a relative and absolute shareholder return, which measures the Company's total shareholder return as compared to the total shareholder return of the defined peer group. As of December 31, 2018, there was $0.3 million of unrecognized compensation cost related to shares of market based performance restricted stock units which is expected to be recognized over a weighted average period of 2.0 years.
Relative | Absolute | |||||||||||||||||
Shares | Weighted Average Grant Date Fair Value | Weighted Average Remaining Vesting Period | Shares | Weighted Average Grant Date Fair Value | Weighted Average Remaining Vesting Period | |||||||||||||
Unvested as of January 1, 2018 | — | — | ||||||||||||||||
Granted | 45,218 | $ | 8.59 | 2.0 years | 45,218 | $ | 4.38 | 2.0 years | ||||||||||
Forfeited | (9,736 | ) | (9,736 | ) | ||||||||||||||
Unvested as of December 31, 2018 | 35,482 | $ | 8.59 | 2.0 years | 35,482 | $ | 4.38 | 2.0 years | ||||||||||
Note 10 — Risk Concentrations
Customer Concentrations
For the year ended December 31, 2018, one customer, EOG Resources, accounted for approximately 20% of the Company’s total revenues. At December 31, 2018, approximately 12% of the accounts receivable balance was due from this customer.
For the year ended December 31, 2017, two customers, EOG Resources and PDC Energy, accounted for approximately 14% and 16% of the Company’s total revenues, respectively. At December 31, 2017, approximately 20% of the accounts receivable balance was due from these customers.
Note 11 — Income Taxes
RNGR Energy Services, LLC is treated as a partnership for U.S. federal income tax purposes and is not subject to federal or state income taxation. As a partner in Ranger Energy Services, LLC, the Company is subject to U.S. taxation on our allocable share of U.S. taxable income and the non-controlling interest members will pay taxes with respect to its allocable share of U.S. taxable income.
The Company is a corporation and is subject to U.S. federal income tax. The tax implications of the Offering and the Company’s concurrent corporate reorganization, and the tax impact of the Company’s status as a taxable corporation subject to U.S. federal income tax have been reflected in the accompanying consolidated financial statements. The effective U.S. federal income tax rate applicable to the Company for the year ended December 31, 2018 and 2017 was 21% and 35%, respectively. Total income tax expense for the year ended December 31, 2018 differed from amounts computed by applying the U.S. federal statutory
F-19
tax rate of 21% primarily due to the increase in the valuation allowance against the deferred tax assets in addition to the adjustment for non-controlling interest that is not subject to federal tax.
Year Ended December 31, | |||||||
2018 | 2017 | ||||||
Current (benefit) provision | |||||||
Federal | $ | — | $ | — | |||
State | (0.2 | ) | 0.4 | ||||
Total current (benefit) provision | (0.2 | ) | 0.4 | ||||
Deferred (benefit) provision | |||||||
Federal | — | — | |||||
State | 0.2 | — | |||||
Total deferred (benefit) expense | 0.2 | — | |||||
Income tax (benefit) expense | $ | — | $ | 0.4 | |||
A reconciliation of the expected income tax expense on income (loss) before income taxes using the statutory federal income tax rate of 21% for 2018 to income tax expense follows (in millions):
December 31, | |||||||
2018 | 2017 | ||||||
Loss before income taxes | $ | (5.8 | ) | $ | (26.9 | ) | |
Statutory rate | 21 | % | 35 | % | |||
Income tax benefit computed at statutory rate | $ | (1.2 | ) | $ | (9.4 | ) | |
Reconciling items | |||||||
State income taxes (benefit), net of federal tax benefit | $ | — | $ | 0.2 | |||
Nontaxable income allocated to non-controlling interest | 0.6 | 1.9 | |||||
Nontaxable income allocated to predecessor | — | 5.3 | |||||
Change in rates | — | 1.4 | |||||
Valuation allowance | — | 1.0 | |||||
Non-deductible expenses and other | 0.6 | — | |||||
Income tax expense | $ | — | $ | 0.4 | |||
As a result of the Offering and subsequent reorganization, the Company recorded a deferred tax asset; however, a full valuation allowance has been recorded to reduce the Company’s net deferred tax assets to an amount that is more likely than not to be realized and is based upon the uncertainty of the realization of certain federal and state deferred tax assets related to net operating loss carryforwards and other tax attributes. The tax effects of the cumulative temporary differences resulting in the net deferred income tax asset (liability) are as follows (in millions):
December 31, | |||||||
2018 | 2017 | ||||||
Deferred income tax assets | |||||||
Equity based compensation | $ | — | $ | 0.3 | |||
Net operating loss carryforward | 15.7 | 6.2 | |||||
Total non-current deferred income tax asset | 15.7 | 6.5 | |||||
Valuation allowance | (5.4 | ) | (2.3 | ) | |||
Net non-current deferred income tax asset | 10.3 | 4.2 | |||||
Deferred income tax liabilities | |||||||
Investment in partnership | (10.3 | ) | (4.2 | ) | |||
Property and equipment | (0.2 | ) | $ | — | |||
Total non-current deferred income tax liability | $ | (0.2 | ) | $ | — | ||
F-20
As of December 31, 2018, the Company has net operating loss carryforwards of approximately $78.9 million, consisting of $18.4 million of section 382 limited losses expiring beginning in 2033, an estimated $20.7 million of non-section 382 limited losses expiring beginning in 2038 and $39.8 million of non-section 382 limited losses which carryforward indefinitely.
Note 12 — Loss per Share
Loss per share is based on the amount of income allocated to the shareholders and the weighted average number of shares outstanding during the period for each class of common stock.
Losses related to periods prior to the reorganization and the Offering are attributable to the Predecessor. The following table presents the Company’s calculation of basic and diluted loss per share for the year ended December 31, 2018 (dollars in millions, except share and per share amounts):
Year Ended December 31, | |||||||
2018 | 2017 | ||||||
Loss (numerator): | |||||||
Basic: | |||||||
Net loss attributable to Ranger Energy Services, Inc. | $ | (3.3 | ) | $ | (6.6 | ) | |
Less: Undistributed earnings allocable to Class B Common Stock | — | — | |||||
Net loss attributable to Class A Common Stock | $ | (3.3 | ) | $ | (6.6 | ) | |
Diluted: | |||||||
Net loss attributable to Ranger Energy Services, Inc. | $ | (3.3 | ) | (6.6 | ) | ||
Less: Undistributed earnings allocable to Class B Common Stock | — | — | |||||
Net loss attributable to Class A Common Stock | $ | (3.3 | ) | $ | (6.6 | ) | |
Weighted average shares (denominator): | |||||||
Weighted average number of shares - basic | 8,425,593 | 8,413,178 | |||||
Weighted average number of shares - diluted | 8,425,593 | 8,413,178 | |||||
Basic loss per share | $ | (0.39 | ) | $ | (0.78 | ) | |
Diluted loss per share | $ | (0.39 | ) | $ | (0.78 | ) | |
During the year ended December 31, 2018, the Company excluded 6.9 million Common Stock issuable upon conversion of the Company's Class B Common Stock , 0.5 million equity-based awards and 0.2 million Common Stock issuable upon payment of CSL liability, in calculating diluted loss per share, as the effect was anti-dilutive. For the year ended December 31, 2017, the Company excluded 6.9 million Common Stock issuable upon conversion of the Company's Class B Common Stock and 0.2 million Common Stock issuable upon payment of CSL liability, in calculating diluted loss per share, as the effect was anti-dilutive.
Note 13 — Commitments and Contingencies
Operating Leases
The Company is obligated under non-cancelable operating leases for facilities and equipment which expire at various dates through 2027. These leases generally contain renewal options for periods ranging from one to five years and require the Company to pay all executory costs (property taxes, maintenance and insurance). Rental payments include minimum rentals.
Aggregate future minimum rental payments as of December 31, 2018 required under these leases are as follows (in millions):
F-21
Year Ended December 31, | Total | ||
2019 | $ | 2.9 | |
2020 | 2.3 | ||
2021 | 0.9 | ||
2022 | 0.7 | ||
2023 | 0.7 | ||
Thereafter | 3.0 | ||
Total future minimum lease payments | $ | 10.5 | |
Legal Matters
From time to time, the Company is involved in various legal matters arising in the normal course of business. The Company does not believe that the ultimate resolution of these matters will have a material adverse effect on its consolidated financial position or results of operations.
During the year ended December 31, 2018, we provided notice to ESCO Leasing, LLC that we are seeking to be indemnified for breach of our contract. We exercised our right to stop payments of the remaining principal balance of $5.8 million on the Seller's Notes and any unpaid interest, pending resolution of certain indemnification claims.
Employee Severance
In March 2017, Ranger Services terminated the employment of one of its officers. As a result, the former officer became entitled to severance payments of $0.7 million. In addition during the year ended December 31, 2018 and 2017, Ranger severed other officers and employees. As of December 31, 2018 and 2017, Ranger had $0.4 million and $1.0 million, respectively, of severance liability recorded in the accompanying consolidated financial statements.
Note 14 — Related Party Transactions
Stockholders’ Agreement
In connection with the Offering, Ranger entered into a stockholders’ agreement (the “Stockholders’ Agreement”) with the Existing Owners and the Bridge Loan Lenders (defined below). Among other things, the Stockholders’ Agreement provides CSL and Bayou Wells Holdings Company, LLC (“Bayou Holdings”) with the right to designate nominees to Ranger’s board of directors (each, as applicable, a “CSL Director” or “Bayou Director”) as follows:
• | for so long as CSL beneficially owns at least 50% of Ranger’s common stock, at least three members of the Board of Directors shall be CSL Directors and at least two members of the Board of Directors shall be Bayou Directors (which may include Richard Agee, Brett Agee or any other person that may be designated by Bayou Holdings in accordance with the terms of the stockholders’ agreement); |
• | for so long as CSL beneficially owns less than 50% but at least 30% of Ranger’s common stock, at least three members of the Board of Directors shall be CSL Directors; |
• | for so long as CSL beneficially owns less than 30% but at least 20% of Ranger’s common stock, at least two members of the Board of Directors shall be CSL Directors; |
• | for so long as CSL beneficially owns less than 20% but at least 10% of Ranger’s common stock, at least one member of the Board of Directors shall be a CSL Director; and |
• | once CSL beneficially owns less than 10% of Ranger’s common stock, CSL will not have any Board designation rights. |
In the event the size of Ranger’s Board of Directors is increased or decreased at any time to other than eight directors, CSL’s nomination rights will be proportionately increased or decreased, respectively, rounded up to the nearest whole number.
Redemption Rights
Under the Ranger LLC Agreement, holders of Ranger Units (the “Ranger Unit Holders”) (other than Ranger) will, subject to certain limitations, have the right, pursuant to the Redemption Right (as defined in the Ranger LLC Agreement), to cause Ranger LLC to acquire all or a portion of their Ranger Units (along with a corresponding number of shares of Ranger’s Class B
F-22
Common Stock) for, at Ranger LLC's election, (i) shares of Ranger’s Class A Common Stock at a redemption ratio of one share of Class A Common Stock for each Ranger Unit redeemed, subject to conversion rate adjustments for stock splits, stock dividends, reclassification and other similar transactions, or (ii) cash in an amount equal to the Cash Election Value (defined below) of such Class A Common Stock. The Company will determine whether to issue shares of Class A Common Stock or cash in an amount equal to the Cash Election Value based on facts in existence at the time of the decision, which Ranger expects would include the trading prices for the Class A Common Stock at the time relative to the cash purchase price for the Ranger Units, the availability of other sources of liquidity (such as an issuance of preferred stock) to acquire the Ranger Units and alternative uses for such cash. Alternatively, upon the exercise of the Redemption Right, Ranger (instead of Ranger LLC) will have the right, pursuant to the Call Right (as defined in the Ranger LLC Agreement), to, for administrative convenience, acquire each tendered Ranger Unit directly from such Ranger Unit Holder for, at Ranger’s election, (x) one share of Class A Common Stock or (y) cash in an amount equal to the value of a share of Class A Common Stock, based on a volume-weighted average price. In addition, upon a change of control of Ranger, Ranger has the right to require each Ranger Unit Holder (other than Ranger) to exercise its Redemption Right with respect to some or all of such unitholder's Ranger Units. As the Ranger Unit Holders redeem their Ranger Units, Ranger’s membership interest in Ranger LLC will be correspondingly increased, the number of shares of Class A Common Stock outstanding will be increased, and the number of shares of Class B Common Stock outstanding will be reduced.
Ranger’s acquisition (or deemed acquisition for U.S. federal income tax purposes) of Ranger Units pursuant to an exercise of the Redemption Right or the Call Right is expected to result in adjustments to the tax basis of the tangible and intangible assets of Ranger LLC, and such adjustments will be allocated to the Company. These adjustments would not have been available to Ranger absent the acquisition or deemed acquisition of Ranger Units and are expected to reduce the amount of cash tax that Ranger would otherwise be required to pay in the future.
“Cash Election Value” means, with respect to the shares of Class A Common Stock to be delivered to the redeeming Ranger Unit Holder by us pursuant to our Call Right, the amount that would be received if the number of shares of Class A Common Stock to which the redeeming Ranger Unit Holder would otherwise be entitled were sold at a per share price equal to the trailing 10-day volume weighted average price of a share of Class A Common Stock on such redemption, net of actual or deemed offering expenses.
Payments
The Company incurred approximately $0.2 million and $1.4 million in expenses to CSL and board members for the years ended December 31, 2018 and 2017, respectively. As of December 31, 2018 amounts due to CSL and board members were negligible.
The Company has recorded a $3.0 million liability, as part of the reorganization, payable on or prior to the 18-month anniversary of the consummation of the Offering in, at the Company’s option, cash, shares of Class A Common Stock (with such shares to be valued based on the greater of the initial public offering price of the Class A Common Stock in the Offering and a 30-day volume-weighted average price) or a combination thereof. This is included as other current liabilities on the consolidated balance sheets.
Acquisition
In January 2017, Ranger Services, through its wholly owned subsidiary, entered into a purchase agreement (the “Allied Purchase Agreement”) with Allied Energy Real Estate, LLC (“Allied Energy”). CSL, which employs certain members of the Company’s Board holds a majority of the voting power of the Company’s common stock and is an indirect owner of Allied Energy. Pursuant to the Allied Purchase Agreement, Ranger Services purchased certain real property in Milliken, Colorado from Allied Energy for a purchase price of $4.0 million.
Related Party Debt
In February 2017, Ranger entered into loan agreements (collectively the “Ranger Bridge Loan”) with each of CSL Energy Opportunities II L.P. (“CSL Opportunities II”), CSL Energy Holdings II LLC (“CSL Holdings II”) and Bayou Holdings (together with CSL Holdings II and CSL Energy Opportunities II, the “the Bridge Loan Lenders”) each an indirect equity owner of Ranger Services. The Ranger Bridge Loan, which was obtained to fund capital expenditures and working capital, was evidenced by promissory notes payable to the Bridge Loan Lenders in an aggregate principal amount of $11.1 million, consisting of three individual promissory notes in the principal amounts of (i) $4.4 million payable to CSL Opportunities II, (ii) $3.2 million payable to CSL Holdings II and (iii) $3.6 million payable to Bayou Holdings. The note was secured by substantially all of the Company’s assets (approximately 0.00 of the Company’s total assets as of December 31, 2018). Each note bore interest at a rate of 15% and matured upon the earlier of February 21, 2018 or ten days after the consummation of an initial public offering. The loan agreement included a make‑whole provision in which the Company would pay 125% of the total amount advanced to the Company upon
F-23
settlement. The 125% is inclusive of the 15% interest rate. During April 2017, the Company increased its bridge loan debt by $1.0 million to $12.1 million to fund capital expenditures and working capital. During May 2017, the Company increased its bridge loan debt by $2.5 million and then again by another $2.5 million in June to $17.1 million to fund capital expenditures and working capital. In July 2017, the Company increased its bridge loan debt by $3.9 million to $21.0 million.
In connection with the corporate reorganization on August 16, 2017, all of the Ranger Bridge Loan was converted into equity. For more information about the corporate reorganization please see Note 1 — Organization and Business Operations.
Tax Receivable Agreement
On August 16, 2017, in connection with the Offering, the Company entered into a Tax Receivable Agreement (the “Tax Receivable Agreement”) with certain of the existing Ranger Unit holders and their permitted transferees (each such person, a “TRA Holder” and together, the “TRA Holders”). The Tax Receivable Agreement generally provides for the payment by the Company of 85% of the net cash savings, if any, in U.S. federal, state and local income tax and franchise tax that the Company actually realizes (computed using simplifying assumptions to address the impact of state and local taxes) or is deemed to realize in certain circumstances in periods after the Offering as a result of (i) certain increases in tax basis that occur as a result of the Company’s acquisition (or deemed acquisition for U.S. federal income tax purposes) of all or a portion of such TRA Holder’s Ranger Units in connection with the Offering or pursuant to the exercise of the Redemption Right or the Call Right (each as defined in the Amended and Restated Limited Liability Company Agreement of Ranger LLC) and (ii) imputed interest deemed to be paid by the Company as a result of, and additional tax basis arising from, any payments the Company makes under the Tax Receivable Agreement. The Company will retain the benefit of the remaining 15% of these cash savings. The term of the Tax Receivable Agreement commences on August 16, 2017 and will continue until all tax benefits that are subject to the Tax Receivable Agreement (or the Tax Receivable Agreement is terminated due to other circumstances, including the Company’s breach of a material obligation thereunder or certain mergers, assets sales, other forms of business combination or other changes of control) have been utilized or expired, unless the Company exercises its right to terminate the Tax Receivable Agreement. The payments under the Tax Receivable Agreement will not be conditioned upon a TRA Holder having a continued ownership interest in either Ranger LLC or the Company.
If the Company elects to terminate the Tax Receivable Agreement early or the Tax Receivable Agreement is terminated due to other circumstances (including the Company’s breach of a material obligation thereunder or certain mergers, asset sales other forms of business combinations or other changes of control), its obligations under the Tax Receivable Agreement would accelerate and it would be required to make an immediate payment equal to the present value of the anticipated future tax payments to be made by Ranger under the Tax Receivable Agreement (determined by applying a discount rate of one-year LIBOR plus 150 basis points and based upon certain assumptions and deemed events set forth in the Tax Receivable Agreement). In addition, payments due under the Tax Receivable Agreement will be similarly accelerated following certain mergers or other changes of control.
Registration Rights Agreement
On August 16, 2017, in connection with the closing of the Offering, the Company entered into a Registration Rights Agreement (the “Registration Rights Agreement”) with certain stockholders (the “Holders”).
Pursuant to, and subject to the limitations set forth in, the Registration Rights Agreement, at any time after the 180-day lock-up period, the Holders have the right to require the Company by written notice to prepare and file a registration statement registering the offer and sale of a number of their shares of Class A Common Stock. Reasonably in advance of the filing of any such registration statement, the Company is required to provide notice of the request to all other Holders who may participate in the registration. The Company is required to use all commercially reasonable efforts to maintain the effectiveness of any such registration statement until all shares covered by such registration statement have been sold. Subject to certain exceptions, the Company is not obligated to effect such a registration within ninety 90 days after the closing of any underwritten offering of shares of Class A Common Stock requested by the Holders pursuant to the Registration Rights Agreements. The Company is also not obligated to effect any registration where such registration has been requested by the holders of Registrable Securities (as defined in the Registration Rights Agreement) which represent less than $25 million, based on the five-day volume weighted average trading price of the Class A Common Stock on the New York Stock Exchange.
In addition, pursuant to the Registration Rights Agreement, the Holders have the right to require the Company, subject to certain limitations set forth therein, to effect a distribution of any or all of their shares of Class A Common Stock by means of an underwritten offering. Further, subject to certain exceptions, if at any time the Company proposes to register an offering of its equity securities or conduct an underwritten offering, whether or not for its account, then the Company must notify the Holders of such proposal at least three business days before the anticipated filing date or commencement of the underwritten offering, as
F-24
applicable, to allow them to include a specified number of their shares in that registration statement or underwritten offering, as applicable.
These registration rights are subject to certain conditions and limitations, including the right of the underwriters to limit the number of shares to be included in a registration or offering and the Company’s right to delay or withdraw a registration statement under certain circumstances. The Company will generally pay all registration expenses in connection with its obligations under the Registration Rights Agreement, regardless of whether a registration statement is filed or becomes effective.
The obligations to register shares under the Registration Rights Agreement will terminate as to any Holder when the Registrable Securities held by such Holder are no longer subject to any restrictions on trading under the provisions of Rule 144 under the Securities Act of 1933, as amended (the “Securities Act”), including any volume or manner of sale restrictions. Registrable Securities means all shares of Class A Common Stock owned at any particular point in time by a Holder other than shares (i) sold pursuant to an effective registration statement under the Securities Act, (ii) sold in a transaction pursuant to Rule 144 under the Securities Act, (iii) that have ceased to be outstanding or (iv) that are eligible for resale without restriction and without the need for current public information pursuant to any section of Rule 144 under the Securities Act.
Note 15 — Segment Reporting
Historically, the Company reported two segments, with corporate general and administrative expense categorized as other. During the fourth quarter of 2018, the Company bifurcated the legacy Well Services segment into High Specification Rigs and Completion and Other Services due to the modifications made to its internal reporting and responsibilities of those reporting to the Chief Operating Decision Maker (“CODM”). As a result, the financial information being provided to the CODM has been updated to align with our new internal organization, which resulted in a new reportable segment discussed further below. Future filings will be updated accordingly.
The Company’s operations are located in the United States and organized into three reportable segments: High Specification Rigs, Completion and Other Services and Processing Solutions. Our reportable segments comprise the structure used by our Chief Operating Decision Maker (“CODM”) to make key operating decisions and assess performance during the years presented in the accompanying consolidated financial statements. Our CODM evaluates the segments’ operating performance based on multiple measures including Adjusted EBITDA, rig hours and rig utilization.
We have made certain reclassifications to our prior period operating revenue, cost of sales and general and administrative amounts due to the change in reportable segments whereby our High Specification Rig and Completion and Other Services segments were bifurcated from our legacy Well Services segment as a result of our fourth quarter operating segment changes. None of these reclassifications have an impact on our consolidated operations results, cash flows or financial position.
The following is a description of the segments:
High Specification Rigs. The Company’s High Specification Rigs facilitate operations throughout the lifecycle of a well, including (i) completion (ii) workover; (iii) well maintenance; and (iv) decommissioning . We provide these advanced well services to Exploration & Production (“E&P”) companies, particularly to those operating in unconventional oil and natural gas reservoirs and requiring technically and operationally advanced services. Our high specification rigs are designed to support growing U.S. horizontal well demands. In addition to our core well service rig operations, we offer a suite of complementary services, including fluid management and well service-related equipment rentals.
Completion and Other Services. Our Completion and Other Services segment provides services necessary to bring and maintain a well on production and consists primarily of our wireline and snubbing lines of business along with other, non-rig well services
Processing Solutions. The Company provides a range of proprietary, modular equipment for the processing of rich natural gas streams at the wellhead or central gathering points in basins where drilling and completion activity has outpaced the development of permanent processing infrastructure.
The Company incurs costs, indicated as Other, that are not allocable to any of the operating segments and includes mostly corporate general and administrative expenses as we all as depreciation of office furniture and fixtures and other corporate assets.
F-25
Segment information for the years ended December 31, 2018 and 2017 is as follows (in millions):
Year Ended December 31, 2018 | ||||||||||||||||||||
High Specification Rigs | Completion and Other Services | Processing Solutions | Other | Total | ||||||||||||||||
Revenues | $ | 149.9 | $ | 136.0 | $ | 17.2 | $ | — | $ | 303.1 | ||||||||||
Cost of services | 128.7 | 100.2 | 8.0 | — | 236.9 | |||||||||||||||
Depreciation and amortization | 19.1 | 8.2 | 1.5 | 1.5 | 30.3 | |||||||||||||||
Impairment of goodwill | 9.0 | — | — | — | 9.0 | |||||||||||||||
Operating income (loss) | (6.9 | ) | 27.6 | 7.7 | (30.5 | ) | (2.1 | ) | ||||||||||||
Interest expense, net | — | — | — | (3.7 | ) | (3.7 | ) | |||||||||||||
Net income (loss) | (6.9 | ) | 27.6 | 7.7 | (34.2 | ) | (5.8 | ) | ||||||||||||
Capital expenditures | $ | 29.8 | $ | 35.1 | $ | 10.3 | $ | 0.7 | $ | 75.9 | ||||||||||
As of December 31, 2018 | ||||||||||||||||||||
Property, plant and equipment | $ | 159.2 | $ | 35.0 | $ | 34.3 | $ | 1.3 | $ | 229.8 | ||||||||||
Total assets | $ | 214.1 | $ | 47.0 | $ | 40.1 | $ | 1.3 | $ | 302.5 | ||||||||||
Year Ended December 31, 2017 | ||||||||||||||||||||
High Specification Rigs | Completion and Other Services | Processing Solutions | Other | Total | ||||||||||||||||
Revenues | $ | 108.3 | $ | 37.4 | $ | 8.3 | $ | — | $ | 154.0 | ||||||||||
Cost of services | 93.4 | 29.8 | 3.2 | — | 126.4 | |||||||||||||||
Depreciation and amortization | 10.8 | 5.4 | 1.3 | 0.3 | 17.8 | |||||||||||||||
Impairment of goodwill | — | — | — | — | — | |||||||||||||||
Operating loss | (8.5 | ) | (2.0 | ) | 0.9 | (11.0 | ) | (20.6 | ) | |||||||||||
Interest expense, net | (1.0 | ) | — | (0.1 | ) | (5.2 | ) | (6.3 | ) | |||||||||||
Net loss | (9.9 | ) | (2.0 | ) | 0.8 | (16.2 | ) | (27.3 | ) | |||||||||||
Capital expenditures | $ | 54.5 | $ | — | $ | 1.5 | $ | — | $ | 56.0 | ||||||||||
As of December 31, 2017 | ||||||||||||||||||||
Property, plant and equipment | $ | 148.9 | $ | 8.5 | $ | 25.4 | $ | 6.4 | 189.2 | |||||||||||
Total assets | $ | 213.8 | $ | 11.3 | $ | 28.2 | $ | 6.4 | 259.7 | |||||||||||
F-26
Note 16 — Selected Quarterly Financial Data (Unaudited)
The following table summarizes the unaudited quarterly statements of the Company for 2018 and 2017 (in millions, except per share data):
Three months ended | ||||||||||||||||
March 31, | June 30, | September 30, | December 31, | |||||||||||||
2018 | ||||||||||||||||
Total revenues | $ | 62.6 | $ | 73.1 | $ | 82.1 | $ | 85.3 | ||||||||
Operating income (loss) | (10.8 | ) | 1.0 | 4.4 | 3.3 | |||||||||||
Net income (loss) | (10.3 | ) | (1.2 | ) | 4.0 | 1.7 | ||||||||||
Net income (loss) attributable to Ranger Energy Services, Inc. | (5.7 | ) | (0.7 | ) | 2.1 | 1.0 | ||||||||||
Basic net income (loss) per share | $ | (0.68 | ) | $ | (0.08 | ) | $ | 0.24 | $ | 0.12 | ||||||
Diluted net income (loss) per share | $ | (0.68 | ) | $ | (0.08 | ) | $ | 0.23 | $ | 0.11 | ||||||
2017 | ||||||||||||||||
Total revenues | $ | 29.1 | $ | 33.7 | $ | 41.1 | $ | 50.1 | ||||||||
Operating loss | (5.7 | ) | (4.9 | ) | (4.8 | ) | (5.2 | ) | ||||||||
Net loss | (6.2 | ) | (6.0 | ) | (9.5 | ) | (5.6 | ) | ||||||||
Net loss attributable to Ranger Energy Services, Inc. | — | — | (3.5 | ) | (3.1 | ) | ||||||||||
Basic net loss per share | $ | — | $ | — | $ | (0.42 | ) | $ | (0.36 | ) | ||||||
Diluted net loss per share | $ | — | $ | — | $ | (0.42 | ) | $ | (0.36 | ) | ||||||
Note 17 — Subsequent Events
The Company has an obligation due to CSL in the amount of $3.0 million, as described in the Master Reorganization Agreement and Note 1 — Organization and Business Operations, which was due in February 2019, at the Company's option in cash, shares of Class A common stock or a combination thereof. The Company is evaluating the payment options and will satisfy the obligation by or before March 31, 2019.
F-27