10-K 1 a201710-kxdoc.htm 10-K Document



 
 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549
 
 
FORM 10-K
 
(Mark One)
x
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2017
OR
¨
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from _____ to _____
Commission File Number 001-37988
 
Keane Group, Inc.
(Exact Name of Registrant as Specified in its Charter)
 
Delaware
38-4016639
(State or other jurisdiction
of incorporation or organization)
(I.R.S. Employer
Identification No.)
 
 
2121 Sage Road, Suite 370, Houston, TX
77056
(Address of principal executive offices)
(Zip code)
Registrant’s telephone number, including area code: (713) 960-0381
 
 
 
Title of Each Class
Name of Each Exchange On Which Registered
Common Stock, $0.01, par value
New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act:  None
_______________
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes  x     No  ¨
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes  ¨    No  x
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  x    No  ¨
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  x     No  ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.




Large accelerated filer
¨
Accelerated filer
¨
 
 
 
 
Non-accelerated filer
x  (do not check if a smaller reporting company)
Smaller reporting company
¨
 
 
 
 
Emerging Growth Company
¨
 
 
If an emerging growth company, indicate by check mark if the registrant has elected to not 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  x  
The aggregate market value of the common stock of the registrant held by non-affiliates of the registrant, computed by reference to the price at which the common stock was last sold on June 30, 2017, was approximately $492.4 million.
As of February 26, 2018, the registrant had 112,243,769 shares of common stock outstanding.
 






TABLE OF CONTENTS
 
 
 
 
 
Item 1.
 
 
 
Item 1A.
 
 
 
Item 1B.
 
 
 
Item 2.
 
 
 
Item 3.
 
 
 
Item 4.
 
 
 
 
 
 
 
 
Item 5.
 
 
 
Item 6.
 
 
 
Item 7.
 
 
 
Item 7A.
 
 
 
Item 8.
 
 
 
Item 9.
 
 
 
Item 9A.
 
 
 
Item 9B.
 
 
 
 
 
 
 
 
Item 10.
 
 
 
Item 11.
 
 
 
Item 12.
 
 
 
Item 13.
 
 
 
Item 14.










CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS AND INFORMATION
This Annual Report on Form 10-K contains forward-looking statements, within the meaning of the Private Securities Litigation Reform Act of 1995, which are subject to risks and uncertainties. All statements other than statements of historical facts contained in this Annual Report on Form 10-K, including statements regarding our future operating results and financial position, business strategy and plans and objectives of management for future operations, are forward-looking statements. Our forward-looking statements are generally accompanied by words such as “may,” “should,” “expect,” “believe,” “plan,” “anticipate,” “could,” “intend,” “target,” “goal,” “project,” “contemplate,” “believe,” “estimate,” “predict,” “potential,” or “continue” or the negative of these terms or other similar expressions. Any forward-looking statements contained in this Annual Report on Form 10-K speak only as of the date on which we make them and are based upon our historical performance and on current plans, estimates and expectations. Except as required by law, we have no obligation to update any forward-looking statements. Forward-looking statements contained in this Annual Report on Form 10-K include, but are not limited to, statements about:
•     our business strategy;
•     our plans, objectives, expectations and intentions;
•    our future operating results;
•    the competitive nature of the industry in which we conduct our business, including pricing pressures;
•     crude oil and natural gas commodity prices;
•    demand for services in our industry;
•    legal proceedings and effect of external investigations;
•     the effect of a loss of, or the financial distress of, one or more key customers;
•    our ability to obtain or renew customer contracts;
•     the effect of a loss of, or interruption in operations of, one or more key suppliers;
•    the market price and availability of materials or equipment;
•     technology;
our ability to obtain permits, approvals and authorizations from governmental and third parties and the effects of government regulation;
•     planned acquisitions and future capital expenditures;
•    our ability to successfully integrate RockPile;
•     our ability to service our debt obligations;
financial strategy, liquidity or capital required for our ongoing operations and acquisitions and our ability to raise additional capital;
•     increased costs as a result of being a public company;
•     our status as a controlled company; and
•     our ability or intention to pay dividends or to effectuate repurchases of our common stock.
We caution you that the foregoing list may not contain all of the forward-looking statements made in this Annual Report on Form 10-K.
You should not rely upon forward-looking statements as predictions of future events. We have based the forward-looking statements contained in this Annual Report on Form 10-K primarily on our current expectations and projections about future events and trends that we believe may affect our business, financial condition, results of operations and

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prospects. The outcome of the events described in these forward-looking statements is subject to risks, uncertainties and other factors described in the section entitled Part I, “Item 1A. Risk Factors” and elsewhere in this Annual Report on Form 10-K. Moreover, we operate in a very competitive and rapidly changing environment. New risks and uncertainties emerge from time to time, and it is not possible for us to predict all risks and uncertainties that could have an impact on the forward-looking statements contained in this Annual Report on Form 10-K. We cannot assure you that the results, events and circumstances reflected in any forward-looking statements will be achieved or occur, and actual results, events or circumstances could differ materially from those described in such forward-looking statements. The forward-looking statements made in this Annual Report on Form 10-K relate only to events as of the date on which the statements are made. We undertake no obligation to update any forward-looking statements made in this Annual Report on Form 10-K to reflect events or circumstances after the date of this Annual Report on Form 10-K or to reflect new information or the occurrence of unanticipated events, except as required by law. We may not actually achieve the plans, intentions or expectations disclosed in our forward-looking statements, and you should not place undue reliance on our forward-looking statements. Our forward-looking statements do not reflect the potential impact of any future acquisitions, mergers, dispositions, joint ventures or investments we may make.
This Annual Report on Form 10-K includes market and industry data and certain other statistical information based on third-party sources including independent industry publications, government publications and other published independent sources, such as content and estimates provided by Coras Research, LLC as of December 2017. Coras Research, LLC is not a member of the FINRA or the SIPC and is not a registered broker dealer or investment advisor. Although we believe these third-party sources are reliable as of their respective dates, we have not independently verified the accuracy or completeness of this information. Some data is also based on our own good faith estimates, which are supported by our management’s knowledge of and experience in the markets and businesses in which we operate.
While we are not aware of any misstatements regarding any market, industry or similar data presented herein, such data involves risks and uncertainties and is subject to change based on various factors, including those discussed above and in Part 1, “Item 1A. Risk Factors” in this Annual Report on Form 10-K.
This Annual Report on Form 10-K includes references to utilization of hydraulic fracturing assets. Utilization for our own fleets, as used in this Annual Report on Form 10-K, is defined as the ratio of the average number of deployed fleets to the number of total fleets for a given time period. For the purposes of this Annual Report on Form 10-K, we consider one of our fleets deployed if the fleet has been put in service at least one day during the period for which we calculate utilization. Furthermore, we define active fleets as fleets available for deployment and commissioning fleets as idle hydraulic horsepower being converted to active fleets. As a result, as additional fleets are incrementally deployed, our utilization rate increases.
We define industry utilization as the ratio of the total industry demand of hydraulic horsepower to the total available capacity of hydraulic horsepower, in each case as reported by an independent industry source. Our method for calculating the utilization rate for our own fleets or the industry may differ from the method used by other companies or industry sources which could, for example, be based off a ratio of the total number of days a fleet is put in service to the total number of days in the relevant period.
As used in this Annual Report on Form 10-K, capacity in the hydraulic fracturing business refers to the total number of hydraulic horsepower, regardless of whether such hydraulic horsepower is active and deployed, active and not deployed or inactive. While the equipment and amount of hydraulic horsepower required for a customer project varies, we calculate our total number of fleets, as used in this Annual Report on Form 10-K, by dividing our total hydraulic horsepower by 45,000 hydraulic horsepower.
We believe that our measures of utilization, based on the number of deployed fleets, provide an accurate representation of existing, available capacity for additional revenue generating activity.
As used in this Annual Report on Form 10-K, references to cannibalization of parked equipment refer to the removal of parts and components (such as the engine or transmission of a fracturing pump) from an idle hydraulic fracturing fleet in order to service an active hydraulic fracturing fleet.

BASIS OF PRESENTATION IN THIS ANNUAL REPORT ON FORM 10-K
On January 25, 2017, we consummated an initial public offering (“IPO”). Our business prior to the IPO was conducted through Keane Group Holdings, LLC and its consolidated subsidiaries (“Keane Group”). To effectuate the IPO, we completed a series of transactions that resulted in a reorganization of our business, resulting in Keane Group, Inc. as a

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holding company with no material assets other than its ownership of Keane Group. For further details, see Note (1) Basis of Presentation and Nature of Operations of Part II, “Item 8. Financial Statements and Supplemental Data.”
Unless otherwise indicated, or the context otherwise requires, for periods prior to the completion of the IPO, (i) the historical financial data in this Annual Report on Form 10-K and (ii) the operating and other non-financial data disclosed in Part II, “Item 6. Selected Financial Data” and Part II, “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” (collectively, the “Financial Statement Sections”) reflect the consolidated business and operations of Keane Group. Financial results for 2016 are the financial results of Keane Group, Inc. and Keane Group Holdings, LLC, the Company's predecessor for accounting purposes, as there was no activity under Keane Group, Inc. in 2016.



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PART I
References Within This Annual Report
As used in Part I of this Annual Report on Form 10-K, unless the context otherwise requires, references to (i) the terms “Company,” “Keane,” “we,” “us” and “our” refer to Keane Group Holdings, LLC and its consolidated subsidiaries for periods prior to our IPO, and, for periods as of and following the IPO, Keane Group, Inc. and its consolidated subsidiaries; (ii) the term “Keane Group” refers to Keane Group Holdings, LLC and its consolidated subsidiaries; (iii) the term “Trican Parent” refers to Trican Well Service Ltd. and, where appropriate, its subsidiaries; (iv) the term “Trican U.S.” refers to Trican Well Service L.P.; (v) the term “Trican” refers to Trican Parent and Trican U.S., collectively; (vi) the term "RockPile" refers to RockPile Energy Services, LLC and its consolidated subsidiaries; (vii) the term "Keane Investor" refers to Keane Investor Holdings LLC and (viii) the terms “Sponsor” or “Cerberus” refer to Cerberus Capital Management, L.P. and its controlled affiliates and investment funds.
Item 1. Business
General description of the business
Founded in 1973, Keane Group, Inc. is one of the largest pure-play providers of integrated well completion services in the U.S., with a focus on complex, technically demanding completion solutions. We provide our services in conjunction with onshore well development, in addition to stimulation operations on existing wells, to exploration and production (“E&P”) customers with some of the highest quality and safety standards in the industry. Through organic growth and four opportunistic acquisitions between 2013 and 2017, we operate in the most active unconventional oil and natural gas basins in the U.S., including the Permian Basin, the Marcellus Shale/Utica Shale, the Eagle Ford Formation and the Bakken Formation, with approximately 1.2 million hydraulic horsepower spread across 26 hydraulic fracturing fleets, 31 wireline trucks, 24 cementing pumps and other ancillary assets. The five cornerstones of our operating principles and culture continue to be focus on health, safety and environment; efficiency and operational excellence; our partnership with our customers; transparency in our value creation; and our responsibilities to our stakeholders.
In April 2013, we acquired the wireline technologies division of Calmena Energy Services, which provided us with a platform to commence wireline operations in the U.S. In December 2013, we acquired the assets of Ultra Tech Frac Services to establish a presence in the Permian Basin. In March 2016, we acquired the majority of the U.S. assets and assumed certain liabilities of Trican Well Service, L.P. (the “Acquired Trican Operations"), resulting in the expansion of our hydraulic fracturing operations to include approximately 950,000 hydraulic horsepower, increased scale in key operating basins, an expansion in our customer base and significant cost reduction opportunities. The Trican transaction also enhanced our access to proprietary technology and engineering capabilities that have improved our ability to provide engineering solutions. In July 2017, we acquired RockPile Energy Services, LLC, resulting in an increase in our pumping capacity by more than 25% and our expanded presence in the Permian Basin and Bakken Formation. We also acquired a high-quality customer base, expanded our service offerings and capabilities within our Other Services segment and integrated certain members of RockPile’s high caliber management team. We ended 2017 with having placed orders for an aggregate of approximately 150,000 newbuild hydraulic horsepower, representing three additional hydraulic fracturing fleets, that will increase our total hydraulic horsepower to more than 1.3 million upon expected delivery during the second and third quarters of 2018.
We are organized into two reportable segments, consisting of Completion Services, including our hydraulic fracturing and wireline divisions; and Other Services, including our cementing and drilling divisions. Our Completion Services segment accounted for 99%, 98%, and 99% of consolidated revenue during the years ended December 31, 2017, 2016 and 2015, respectively. For further discussion on financial information about our segments, see Note (22) Business Segments of Part II, “Item 8. Financial Statements and Supplementary Data.”

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Completion Services segment
Our completion services are designed in partnership with our customers to enhance both initial production rates and estimated ultimate recovery from new and existing wells.
Hydraulic Fracturing.    Hydraulic fracturing services are performed to enhance production of oil and natural gas from formations with low permeability and restricted flow of hydrocarbons. The process of hydraulic fracturing involves pumping a highly viscous, pressurized fracturing fluid -typically a mixture of water, chemicals and proppant into a well casing or tubing in order to fracture underground mineral formations. These fractures release trapped hydrocarbon particles and free a channel for the oil or natural gas to flow freely to the wellbore for collection. Fracturing fluid mixtures include proppant which become lodged in the cracks created by the hydraulic fracturing process, “propping” them open to facilitate the flow of hydrocarbons upward through the well.
Wireline Technologies.    Our wireline services involve the use of a single truck equipped with a spool of wireline that is unwound and lowered into oil and natural gas wells to convey specialized tools or equipment for well completion, well intervention, pipe recovery and reservoir evaluation purposes. We typically provide our wireline services in conjunction with our hydraulic fracturing services in “plug-and-perf” well completions to maximize efficiency for our customers. “Plug-and-perf” is a multi-stage well completion technique for cased-hole wells that consists of pumping a plug and perforating guns to a specified depth. Once the plug is set, the zone is perforated and the tools are removed from the well, a ball is pumped down to isolate the zones below the plug and the hydraulic fracturing treatment is applied.
Other Services segment
Cementing.    Our cementing services incorporate custom engineered mixing and blending equipment to ensure precision and accuracy in providing annual isolation and hydraulic seal, while protecting fresh water zones of our customers’ zone of interest. Our cement division has the expertise to cement shallow to complex high temperature high pressure wells. We also offer engineering software and technical guidance for remedial cementing applications and acidizing to optimize the performance of our customers' wells.
Drilling.     We are equipped to provide top-hole air drilling services. Our drilling services were idled in May 2015.
Business strategy
Our principal business objective is to increase shareholder value by profitably growing our business, while providing best-in-class completion services, with a strict focus on health, safety and environmental stewardship and cost-effective customer-centric solutions. We expect to achieve this objective through:
capitalizing efficiently on industry recovery;
developing and expanding our relationships with existing and new customers;
continuing our industry leading safety performance and focus on the environment;
investing further in our robust maintenance program;
maintaining a conservative balance sheet to preserve operational and strategic flexibility; and
continuing to evaluate potential consolidation opportunities that strengthen our capabilities and create value.
For further discussion on the business strategies we plan to continue executing in 2018, see Part II, “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

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Customers
Our customers primarily include major integrated and large independent oil and natural gas E&P companies. For the year ended December 31, 2017, no customer represented more than 10% of our consolidated revenue. For the year ended December 31, 2016, three customers, Shell Exploration & Production, XTO Energy and Seneca Resources Corporation, individually represented more than 10% of our consolidated revenue. For the year ended December 31, 2015, four customers, EQT Production Company, XTO Energy, Shell Exploration & Production and Southwestern Energy Company, individually represented more than 10% of our consolidated revenue.
Competition
The markets in which we operate are highly competitive. We provide services in various geographic regions across the U.S., and our competitors include many large and small oilfield service providers, including some of the largest integrated service companies. In addition, the business segments in which we compete are highly fragmented. Our integrated hydraulic fracturing and wireline services compete with large, integrated oilfield service companies such as Halliburton Company, Schlumberger Limited, Weatherford International plc and Baker Hughes Incorporated, as well as other companies such as RPC, Inc., Superior Energy Services, Inc., C&J Energy Services, Inc., Basic Energy Services, Inc. and FTS International, Inc. Our hydraulic fracturing services also compete with Calfrac Well Services Ltd., U.S. Well Services, Patterson-UTI Energy, Inc., ProPetro Services, Inc. and Liberty Oilfield Services. We also compete regionally with a significant number of smaller service providers.
We believe the principal competitive factors in the markets we serve are our multi-basin service capability and close proximity to our customers, our technical expertise, our equipment capacity, our work force competency, our efficiency, our safety record, our reputation, our experience and our prices. Additionally, projects are often awarded on a bid basis, which tends to create a highly competitive environment. While we seek to be competitive in our pricing, we believe many of our customers elect to work with us based on our customer-tailored approach, our safety record, the performance and quality of our crews, our equipment and our services. 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.
Raw materials
We purchase a wide variety of raw materials, parts and components that are manufactured and supplied for our operations. We are not dependent on any single source of supply for those parts, supplies or materials. To date, we have generally been able to obtain the equipment, parts and supplies necessary to support our operations on a timely basis. While we believe we will be able to make satisfactory alternative arrangements in the event of any interruption in the supply of these materials and/or products by one of our suppliers, this may not always be the case. In addition, certain materials for which we do not currently have long-term supply agreements, such as guar (which experienced a shortage and significant price increase in 2012), could experience shortages and significant price increases in the future.
In March 2016, in connection with the acquisition of the Acquired Trican Operations, Keane received the right to use certain Trican proprietary fracking-related fluids as of the closing date of the Trican transaction, such as MVP Frac™ and TriVert™ (the “Fracking Fluids”), for Keane’s pressure pumping services to its customers. The license does not allow Keane to manufacture the Fracking Fluids, but allows Keane to purchase the Fracking Fluids from Trican’s suppliers.
The industry continues to face strain in sand supply, driven by weather-induced rail congestion, combined with mine-related issues due to rail-related output constraints, flooding impacts, delays on local mine start-ups and continued growth in demand. We are proactively managing these transitory issues facing the entire industry to limit the impact to our customers and business.

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Research and Development costs
Our engineering and technology efforts are focused on providing cost-effective solutions to the challenges our customers face when fracturing and stimulating wells. We believe our Engineered Solutions Center, located in The Woodlands, Texas, enables us to support our customers’ technical specifications, by offering flexible, cost-effective design solutions that package our services with new and existing product offerings. Our Engineered Solutions Center is focused on providing (i) economical and effective fracture designs, (ii) enhanced fracture stimulation methods, (iii) next-generation fluids and technologically advanced diverting agents, such as MVP Frac™ and TriVert™, which we received the right to use as part of the Trican transaction, (iv) dust control technologies and (v) customized solutions to individual customer and reservoir requirements.
We incurred research and development costs of $3.7 million, $2.2 million and nil for the years ended December 31, 2017, 2016 and 2015, respectively.
Intellectual property
In connection with the acquisition of the Acquired Trican Operations, we acquired ownership of substantially all intellectual property relating primarily to Trican’s U.S. oilfield services business, which includes know-how, trade secrets, formulas, processes, customer lists and other non-registered intellectual property primarily used in connection with that business. Keane also entered into two fully paid-up, perpetual, non-exclusive licenses to certain intellectual property owned by Trican or its affiliates. See Part III, “Item 13. Certain Relationships and Related-Party Transactions and Director Independence-Trican Transaction” for more information. We believe the proprietary technology and engineering capabilities acquired in the Trican transaction have enhanced our integrated services solutions and better positioned our company to meet our customers’ technical demands.
We believe the information regarding our customer and supplier relationships are also valuable proprietary assets. We have pending applications and registered trademarks for various names under which our entities conduct business or provide products or services. Except for the foregoing, we do not own or license any patents, trademarks or other intellectual property that we believe to be material to the success of our business.
Seasonality
Weather conditions affect the demand for, and prices of, oil and natural gas and, as a result, demand for our services. Demand for oil and natural gas is typically higher in the fourth and first quarters resulting in higher prices. Due to these seasonal fluctuations, results of operations for individual quarterly periods may not be indicative of the results that may be realized on an annual basis.
Employees
As of December 31, 2017, we employed 2,748 people, of which approximately 80% were compensated on an hourly basis. Our employees are not covered by collective bargaining agreements, nor are they members of labor unions. While we consider our relationship with our employees to be satisfactory, disputes may arise over certain classifications of employees that are customary in the oilfield services industry. We are not aware of any other potentially adverse matters involving our employment practices.
Environmental regulation
Our operations are subject to stringent federal, state and local laws, rules and regulations relating to the oil and natural gas industry, including the discharge of materials into the environment or otherwise relating to health and safety or the protection of the environment. Numerous governmental agencies, such as the Environmental Protection Agency (the “EPA”), issue regulations to implement and enforce these laws, which often require costly compliance measures. Failure to comply with these laws and regulations may result in the assessment of substantial administrative, civil and criminal penalties, expenditures associated with exposure to hazardous materials, remediation of contamination, property damage and personal injuries, imposition of bond requirements, as well as the issuance of injunctions limiting or prohibiting our activities. In addition, some laws and regulations relating to

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protection of the environment may, in certain circumstances, impose strict liability for environmental contamination, rendering a person liable for environmental damages and clean-up costs without regard to negligence or fault on the part of that person. Strict adherence with these regulatory requirements increases our cost of doing business and consequently affects our profitability. However, environmental laws and regulations have been subject to frequent changes over the years, and the imposition of more stringent requirements, including those that result in any limitation, suspension or moratorium on the services we provide, whether or not short-term in nature, by federal, state, regional or local governmental authority, could have a material adverse effect on our business, financial condition and results of operations.
The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA” or the “Superfund law”), and comparable state laws impose liability on certain classes of persons that are considered to be responsible for the release of hazardous or other state-regulated substances into the environment. These persons include the current or former owner or operator of the site where the release occurred and the parties that disposed or arranged for the disposal or treatment of hazardous or other state-regulated substances that have been released at the site. Under CERCLA, these persons may be subject to strict liability, joint and several liability, or both, for the costs of investigating and cleaning up hazardous substances that have been released into the environment, damages to natural resources and health studies without regard to fault. In addition, companies that incur a CERCLA liability frequently confront claims by neighboring landowners and other third parties for personal injury and property damage allegedly caused by the release of hazardous or other regulated substances or pollutants into the environment.
The federal Solid Waste Disposal Act, as amended by the Resource Conservation and Recovery Act of 1976, (“RCRA”) and analogous state law generally excludes oil and gas exploration and production wastes (e.g., drilling fluids, produced waters) from regulation as hazardous wastes. However, these wastes remain subject to potential regulation as solid wastes under RCRA and as hazardous waste under other state and local laws. Moreover, wastes from some of our operations (such as, but not limited to, our chemical development, blending and distribution operations, as well as some maintenance and manufacturing operations) are or may be regulated under RCRA and analogous state law under certain circumstances. Further, any exemption or regulation under RCRA does not alter treatment of the substance under CERCLA.
From time to time, releases of materials or wastes have occurred at locations we own or at which we have operations. These properties and the materials or wastes released thereon may be subject to CERCLA, RCRA, the federal Clean Water Act, the Safe Drinking Water Act (the “SDWA”) and analogous state laws. Under these laws or other laws and regulations, we have been and may be required to remove or remediate these materials or wastes and make expenditures associated with personal injury or property damage. At this time, with respect to any properties where materials or wastes may have been released, it is not possible to estimate the potential costs that may arise from unknown, latent liability risks.
There has been increasing public controversy regarding hydraulic fracturing with regard to the use of fracturing fluids, impacts on drinking water supplies, use of water and the potential for impacts to surface water, groundwater and the environment generally. Companion bills entitled the Fracturing Responsibility and Awareness Chemicals Act (“FRAC Act”) were reintroduced in the House of Representatives in May 2013 and in the United States Senate in June 2013. If the FRAC Act and other similar legislation pass, the legislation could significantly alter regulatory oversight of hydraulic fracturing. Currently, unless the fracturing fluid used in the hydraulic fracturing process contains diesel fuel, hydraulic fracturing operations are exempt from permitting under the Underground Injection Control (“UIC”) program in the SDWA. The FRAC Act would remove this exemption and subject hydraulic fracturing operations to permitting requirements under the UIC program. The FRAC Act and other similar bills propose to also require persons conducting hydraulic fracturing to disclose the chemical constituents of their fracturing fluids to a regulatory agency, although they would not require the disclosure of the proprietary formulas except in cases of emergency. Currently, several states already require public disclosure of non-proprietary chemicals on FracFocus.org and other equivalent Internet sites. Disclosure of our proprietary chemical formulas to third parties or to the public, even if inadvertent, could diminish the value of those formulas and could result in

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competitive harm to our business. At this time, it is not clear what action, if any, the United States Congress will take on the FRAC Act or other related federal and state bills, or the ultimate impact of any such legislation.
If the FRAC Act or similar legislation becomes law, or the Department of the Interior or another federal agency asserts jurisdiction over certain aspects of hydraulic fracturing operations, additional regulatory requirements could be established at the federal level that could lead to operational delays or increased operating costs, making it more difficult to perform hydraulic fracturing and increasing the costs of compliance and doing business for us and our customers. States in which we operate have considered and may again consider legislation that could impose additional regulations and/or restrictions on hydraulic fracturing operations. At this time, it is not possible to estimate the potential impact on our business of these state actions or the enactment of additional federal or state legislation or regulations affecting hydraulic fracturing.
In addition, at the direction of Congress, the EPA undertook a study of the potential impacts of hydraulic fracturing on drinking water and groundwater and issued its report in December 2016. The EPA report states that there is scientific evidence that hydraulic fracturing activities can impact drinking resources under some circumstances and identifies certain conditions in which the EPA believes the impact of such activities on drinking water and groundwater can be more frequent or severe. The EPA study could spur further initiatives to regulate hydraulic fracturing under the SDWA or otherwise. Similarly, other federal and state studies, such as those currently being conducted by, for example, the Secretary of Energy’s Advisory Board and the New York Department of Environmental Conservation, may recommend additional requirements or restrictions on hydraulic fracturing operations.
The federal Clean Air Act and comparable state laws regulate emissions of various air pollutants through air emissions permitting programs and the imposition of other requirements. In addition, the EPA has developed and continues to develop stringent regulations governing emissions of toxic air pollutants from specified sources. We are or may be required to obtain federal and state permits in connection with certain operations of our manufacturing and maintenance facilities. These permits impose certain conditions and restrictions on our operations, some of which require significant expenditures for filtering or other emissions control devices at each of our manufacturing and maintenance facilities. Changes in these requirements, or in the permits we operate under, could increase our costs or limit certain activities. Additionally, the EPA’s Transition Program for Equipment Manufacturers regulations apply to certain off-road diesel engines used by us to power equipment in the field. Under these regulations, we are subject to certain requirements with respect to retrofitting or retiring certain engines, and we are limited in the number of new non-compliant off-road diesel engines we can purchase. Engines that are compliant with the current emissions standards can be costlier and can be subject to limited availability. It is possible that these regulations could limit our ability to acquire a sufficient number of diesel engines to expand our fleet and/or upgrade our existing equipment by replacing older engines as they are taken out of service.
Exploration and production activities on federal lands may be subject to the National Environmental Policy Act (“NEPA”). NEPA requires federal agencies, including the Department of Interior, to evaluate major agency actions that have the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an environmental assessment of the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed environmental impact statement that may be made available for public review and comment. All of our activities and our customers’ current E&P activities, as well as proposed exploration and development plans, on federal lands require governmental permits that are subject to the requirements of NEPA. This process has the potential to delay the development of oil and natural gas projects.
Various state and federal statutes prohibit certain actions that adversely affect endangered or threatened species and their habitat, migratory birds, wetlands and natural resources. These statutes include the Endangered Species Act, the Migratory Bird Treaty Act, the Clean Water Act and CERCLA. Government entities or private parties may act to prevent oil and gas exploration activities or seek damages where harm to species, habitat or natural resources may result from the filling of jurisdictional streams or wetlands or the construction or release of oil, wastes, hazardous substances or other regulated materials. At this time, it is not possible to estimate the potential impact on our business of these speculative federal, state or private actions or the enactment of additional federal or state legislation or regulations with respect to these matters.

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The EPA has proposed and finalized a number of rules requiring various industry sectors to track and report, and, in some cases, control greenhouse gas emissions. The EPA’s Mandatory Reporting of Greenhouse Gases Rule was published in October 2009. This rule requires large sources and suppliers in the U.S. to track and report greenhouse gas emissions. In June 2010, the EPA’s Greenhouse Gas Tailoring Rule became effective. For this rule to apply initially, the source must already be subject to the Clean Air Act Prevention of Significant Deterioration program or Title V permit program; we are not currently subject to either Clean Air Act program. On November 8, 2010, the EPA finalized a rule that sets forth reporting requirements for the petroleum and natural gas industry. Among other things, this final rule requires persons that hold state permits for onshore oil and gas exploration and production and that emit 25,000 metric tons or more of carbon dioxide equivalent per year to annually report carbon dioxide, methane and nitrous oxide combustion emissions from (i) stationary and portable equipment and (ii) flaring. Under the final rule, our customers may be required to include calculated emissions from our hydraulic fracturing equipment located on their well sites in their emission inventory.
The trajectory of future greenhouse regulations remains unsettled. In March 2014, the White House announced its intention to consider further regulation of methane emissions from the oil and gas sector. It is unclear whether Congress will take further action on greenhouse gases, for example, to further regulate greenhouse gas emissions or alternatively to statutorily limit the EPA’s authority over greenhouse gases. Even without federal legislation or regulation of greenhouse gas emissions, states may pursue the issue either directly or indirectly. Restrictions on emissions of methane or carbon dioxide that may be imposed in various states could adversely affect the oil and natural gas industry and, therefore, could reduce the demand for our products and services.
Climate change regulation may also impact our business positively by increasing demand for natural gas for use in producing electricity and as a transportation fuel. Currently, our operations are not materially adversely impacted by existing state and local climate change initiatives. At this time, we cannot accurately estimate how potential future laws or regulations addressing greenhouse gas emissions would impact our business.
We seek to minimize the possibility of a pollution event through equipment and job design, as well as through training employees. We also maintain a pollution risk management program in the event a pollution event occurs. This program includes an internal emergency response plan that provides specific procedures for our employees to follow in the event of a chemical release or spill. In addition, we have contracted with several third-party emergency responders in our various operating areas that are available on a 24-hour basis to handle the remediation and clean-up of any chemical release or spill. We carry insurance designed to respond to foreseeable environmental pollution events. This insurance portfolio has been structured in an effort to address pollution incidents that result in bodily injury or property damage and any ensuing clean up required at our owned facilities, as a result of the mobilization and utilization of our fleets, as well as any environmental claims resulting from our operations.
We also seek to manage environmental liability risks through provisions in our contracts with our customers that generally allocate risks relating to surface activities associated with the fracturing process, other than water disposal, to us and risks relating to “down-hole” liabilities to our customers. Our customers are responsible for the disposal of the fracturing fluid that flows back out of the well as waste water, for which they use a controlled flow-back process. We are not involved in that process or the disposal of the fluid. Our contracts generally require our customers to indemnify us against pollution and environmental damages originating below the surface of the ground or arising out of water disposal, or otherwise caused by the customer, other contractors or other third parties. In turn, we generally indemnify our customers for pollution and environmental damages originating at or above the surface caused solely by us. We seek to maintain consistent risk-allocation and indemnification provisions in our customer agreements to the extent possible. Some of our contracts, however, contain less explicit indemnification provisions, which typically provide that each party will indemnify the other against liabilities to third parties resulting from the indemnifying party’s actions, except to the extent such liability results from the indemnified party’s gross negligence, willful misconduct or intentional act.

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Safety and health regulation
Safety is our highest priority, and we believe we are among the safest service providers in the industry. For example, we achieve a total recordable incident rate, which we believe is a reliable measure of safety performance, that is substantially less than the industry average from 2013 to 2016. We believe we have an industry leading behavior-based safety program to ensure each employee understands the importance of safety.
We are subject to the requirements of the federal Occupational Safety and Health Act, which is administered and enforced by the Occupational Safety and Health Administration, commonly referred to as OSHA, and comparable state laws 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. We believe that our operations are in substantial compliance with the OSHA requirements, including general industry standards, record keeping requirements and monitoring of occupational exposure to regulated substances. OSHA continues to evaluate worker safety and to propose new regulations, such as but not limited to, the proposed new rule regarding respirable silica sand. Although it is not possible to estimate the financial and compliance impact of the proposed respirable silica sand rule or any other proposed rule, the imposition of more stringent requirements could have a material adverse effect on our business, financial condition and results of operations.
Insurance
Our operations are subject to hazards inherent in the oil and natural gas industry, including accidents, blowouts, explosions, craterings, fires, oil spills and hazardous materials spills. These conditions can cause personal injury or loss of life, damage to or destruction of property, equipment, the environment and wildlife, and interruption or suspension of operations, among other adverse effects. In addition, claims for loss of oil and natural gas production and damage to formations can occur in the well services industry. If a serious accident were to occur at a location where our equipment and services are being used, it could result in our being named as a defendant to a lawsuit asserting significant claims.

Despite our efforts to maintain high safety standards, we from time to time have suffered accidents in the past and we anticipate that we could experience accidents in the future. In addition to the property and personal losses from these accidents, the frequency and severity of these incidents affect our operating costs and insurability, as well as our relationships with customers, employees and regulatory agencies. Any significant increase in the frequency or severity of these incidents, or the general level of compensation awards, could adversely affect the cost of, or our ability to obtain, workers’ compensation and other forms of insurance, and could have other adverse effects on our financial condition and results of operations.

We carry a variety of insurance coverages for our operations, and we are partially self-insured for certain claims, in amounts that we believe to be customary and reasonable. However, our insurance may not be sufficient to cover any particular loss or may not cover all losses. Historically, insurance rates have been subject to various market fluctuations that may result in less coverage, increased premium costs, or higher deductibles or self-insured retentions.
Availability of filings
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 Securities Exchange Act of 1934, as amended (the “Exchange Act”), are made available free of charge on our internet web site at www.keanegrp.com, as soon as reasonably practicable after we have electronically filed the material with, or furnished it to, the Securities and Exchange Commission (the “SEC”). The public may read and copy any materials we have filed with the SEC at the SEC’s Public Reference Room at 100 F Street, NE, Washington, DC 20549. Information on the operation of the Public Reference Room may be obtained by calling the SEC at 1-800-SEC-0330. The SEC maintains an internet site that contains our reports, proxy and information statements, and our other SEC filings. The address of that web site is https://www.sec.gov/.

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We webcast our earnings calls and certain events we participate in or host with members of the investment community on our investor relations website at https://investors.keanegrp.com/. Additionally, we provide notifications of news or announcements regarding our financial performance, including SEC filings, investor events, press and earnings releases and blogs as part of our investor relations website. We have used, and intend to continue to use, our investor relations website as means of disclosing material information and for complying with our disclosure obligations under Regulation Fair Disclosure. Further corporate governance information, including our certificate of incorporation, bylaws, governance guidelines, board committee charters and code of business conduct and ethics, is also available on our investor relations website under the heading “Corporate Governance.” The contents of our websites are not intended to be incorporated by reference into this Annual Report on Form 10-K or in any other report or document we file with the SEC, and any references to our websites are intended to be inactive textual references only.

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Item 1A. Risk Factors
RISK FACTORS
Described below are certain risks that we believe apply to our business and the industry in which we operate. You should carefully consider each of the following risk factors in conjunction with other information provided in this Annual Report on Form 10-K and in our other public disclosures. The risks described below highlight potential events, trends or other circumstances that could adversely affect our business, financial condition, results of operations, cash flows, liquidity or access to sources of financing, and consequently, the market value of our common stock. These risks could cause our future results to differ materially from historical results and from guidance we may provide regarding our expectations of future financial performance. The risks described below are those that we have identified as material and is not an exhaustive list of all the risks we face. There may be others that we have not identified or that we have deemed to be immaterial. All forward-looking statements made by us or on our behalf are qualified by the risks described below.
Risks Related to Our Business and Industry
Our business is cyclical and depends on spending and well completions by the onshore oil and natural gas industry in the U.S., and the level of such activity is volatile. Our business has been, and may continue to be, adversely affected by industry conditions that are beyond our control.
Our business is cyclical, and we depend on the willingness of our customers to make expenditures to explore for, develop and produce oil and natural gas from onshore unconventional resources in the U.S. The willingness of our customers to undertake these activities depends largely upon prevailing industry conditions that are influenced by numerous factors over which we have no control, including:
prices, and expectations about future prices, for oil and natural gas;
domestic and foreign supply of, and demand for, oil and natural gas and related products;
the level of global and domestic oil and natural gas inventories;
the supply of and demand for hydraulic fracturing and other oilfield services and equipment in the United States;
the cost of exploring for, developing, producing and delivering oil and natural gas;
available pipeline, storage and other transportation capacity;
lead times associated with acquiring equipment and products and availability of qualified personnel;
the discovery rates of new oil and natural gas reserves;
federal, state and local regulation of hydraulic fracturing and other oilfield service activities, as well as exploration and production activities, including public pressure on governmental bodies and regulatory agencies to regulate our industry;
the availability of water resources, suitable proppant and chemicals in sufficient quantities for use in hydraulic fracturing fluids;
geopolitical developments and political instability in oil and natural gas producing countries;
actions of the Organization of the Petroleum Exporting Countries (“OPEC”), its members and other state-controlled oil companies relating to oil price and production controls;

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advances in exploration, development and production technologies or in technologies affecting energy consumption;
the price and availability of alternative fuels and energy sources;
disruptions due to natural disasters, unexpected weather conditions, etc.;
uncertainty in capital and commodities markets and the ability of oil and natural gas producers to raise equity capital and debt financing; and
U.S. federal, state and local and non-U.S. governmental regulations and taxes.
The volatility of the oil and natural gas industry and the resulting impact on exploration and production activity could adversely impact the level of drilling and completion activity by some of our customers. This volatility may result in a decline in the demand for our services or adversely affect the price of our services. In addition, material declines in oil and natural gas prices, or drilling or completion activity in the U.S. oil and natural gas shale regions, could have a material adverse effect on our business, financial condition, prospects, results of operations and cash flows. In addition, a decrease in the development of oil and natural gas reserves in our market areas may also have an adverse impact on our business, even in an environment of strong oil and natural gas prices.
A decline in or substantial volatility of crude oil and natural gas commodity prices could adversely affect the demand for our services.
The demand for our services is substantially influenced by current and anticipated crude oil and natural gas commodity prices and the related level of drilling and completion activity and general production spending in the areas in which we have operations. Volatility or weakness in crude oil and natural gas commodity prices (or the perception that crude oil and natural gas commodity prices will decrease) affects the spending patterns of our customers and the products and services we provide are, to a substantial extent, deferrable in the event oil and natural gas companies reduce capital expenditures. As a result, we may experience lower utilization of, and may be forced to lower our rates for, our equipment and services.
Historical prices for crude oil and natural gas have been extremely volatile and are expected to continue to be volatile. For example, since 1999, oil prices have ranged from as low as approximately $10 per barrel to over $100 per barrel. In recent years, oil and natural gas prices and, therefore, the level of exploration, development and production activity, experienced a sustained decline from the highs in the latter half of 2014 as a result of an increasing global supply of oil and a decision by OPEC to sustain its production levels in spite of the decline in oil prices and slowing economic growth in the Eurozone and China. From late 2014 to second half of 2016, prices
for U.S. oil weakened in response to continued high levels of production by OPEC, a buildup in inventories and lower global demand. OPEC’s recent agreement to reduce its oil production has provided upward momentum for oil and natural gas prices, but member nations may opt to not follow this agreement. Although beginning in late 2016 oil prices and natural gas prices have recovered to $60.46 per barrel and $3.69 per MMbtu, respectively, as of December 29, 2017, the volatility of our industry persists.
As a result of the significant decline in the price of oil, beginning in late 2014, E&P companies moved to significantly cut costs, both by decreasing drilling and completion activity and by demanding price concessions from their service providers, including providers of hydraulic fracturing services. In turn, service providers, including hydraulic fracturing service providers, were forced to lower their operating costs and capital expenditures, while continuing to operate their businesses in an extremely competitive environment. Prolonged periods of price instability in the oil and natural gas industry will adversely affect the demand for our products and services and our financial condition, prospects and results of operations.
Additionally, the commercial development of economically viable alternative energy sources (such as wind, solar geothermal, tidal, fuel cells and biofuels) and fuel conservation measures could reduce demand for our services and create downward pressure on the revenue we are able to derive from such services, as they are dependent on oil and natural gas commodity prices.

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Our operations are subject to hazards inherent in the energy services industry.
Risks inherent to our industry can cause personal injury, loss of life, suspension of or impact upon operations, damage to geological formations, damage to facilities, business interruption and damage to, or destruction of, property, equipment and the environment. Such risks may include, but are not limited to:
equipment defects;
vehicle accidents;
explosions and uncontrollable flows of gas or well fluids;
unusual or unexpected geological formations or pressures and industrial accidents;
blowouts;
cratering;
loss of well control;
collapse of the borehole; and
damaged or lost drilling equipment.
In addition, our hydraulic fracturing and well completion services could become a source of spills or releases of fluids, including chemicals used during hydraulic fracturing activities, at the site where such services are performed, or could result in the discharge of such fluids into underground formations that were not targeted for fracturing or well completion activities, such as potable aquifers. These risks could expose us to substantial liability for personal injury, wrongful death, property damage, loss of oil and natural gas production, pollution and other environmental damages and could result in a variety of claims, losses and remedial obligations that could have an adverse effect on our business and results of operations. The existence, frequency and severity of such incidents could affect operating costs, insurability and relationships with customers, employees and regulators. In particular, our customers may elect not to purchase our services if they view our safety record as unacceptable, which could cause us to lose customers and substantial revenue, and any litigation or claims, even if fully indemnified or insured, could negatively affect our reputation with our customers and the public and make it more difficult for us to compete effectively or obtain adequate insurance in the future.
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. 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. Litigation arising from operations where our facilities are located, or 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. Further, our insurance has deductibles or self-insured retentions and contains certain coverage exclusions. The current trend in the insurance industry is towards larger deductibles and self-insured retentions. In addition, insurance may not be available in the future at rates that we consider reasonable and commercially justifiable, compelling us to have larger deductibles or self-insured retentions to effectively manage expenses. As a result, we could become subject to material uninsured liabilities or situations where we have high deductibles or self-insured retentions that expose us to liabilities that could have a material adverse effect on our business, financial condition, prospects or results of operations.

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Litigation and other proceedings could have a negative impact on our business.
The nature of our business makes us susceptible to legal proceedings and governmental audits and investigations from time to time. In addition, during periods of depressed market conditions, we may be subject to an increased risk of our customers, vendors, current and former employees and others initiating legal proceedings against us could have a material adverse effect on our business, financial condition and results of operations. Similarly, any legal proceedings or claims, even if fully indemnified or insured, could negatively impact our reputation among our customers and the public, and make it more difficult for us to compete effectively or obtain adequate insurance in the future. See Note (18) Commitments and Contingencies of Part II, "Item 8. Financial Statements and Supplementary Data" for further discussion of our legal and environmental contingencies for the years ended December 31, 2017, 2016 and 2015.
Competition within the oilfield services industry may adversely affect our ability to market our services.
The oilfield services industry is highly competitive and fragmented and includes several large companies that compete in many of the markets we serve, as well as numerous small companies that compete with us on a local basis. Our larger competitors’ greater resources could allow them to better withstand industry downturns and to compete more effectively on the basis of technology, geographic scope and retained skilled personnel. We believe the principal competitive factors in the market areas we serve are multi-basin service capability, proximity to customers, technical expertise, equipment capacity, work force competency, efficiency, safety records, reputation experience and price. Our operations may be adversely affected if our current competitors or new market entrants introduce new products or services with better features, performance, prices or other characteristics than our products and services or expand into service areas where we operate. Competitive pressures or other factors may also result in significant price competition, particularly during industry downturns, which could have a material adverse effect on our results of operations, financial condition and prospects. Significant increases in overall market capacity have previously caused price competition and led to lower pricing and utilization levels for our services.
The competitive environment has intensified since late 2014 as a result of the industry downturn and oversupply of oilfield services. We have seen substantial reductions in the prices we can charge for our services based on reduced demand and resulting overcapacity. Any significant future increase in overall market capacity for completion services could adversely affect our business and results of operations.
Our assets require significant amounts of capital for maintenance, upgrades and refurbishment and may require significant capital expenditures for new equipment.
Our hydraulic fracturing fleets and other completion service-related equipment require significant capital investment in maintenance, upgrades and refurbishment to maintain their competitiveness. For example, from April 1, 2016 through December 31, 2017, we commissioned 14 hydraulic fracturing fleets to service customers at a total cost to deploy of $29.0 million, including capital expenditures. Our fleets and other equipment typically do not generate revenue while they are undergoing maintenance, refurbishment or upgrades. Any maintenance, upgrade or refurbishment project for our assets could increase our indebtedness or reduce cash available for other opportunities. Further, such projects may require proportionally greater capital investments as a percentage of total asset value, which may make such projects difficult to finance on acceptable terms. 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 potential or current customers. Additionally, increased demand, competition or advances in technology within our industry may require us to update or replace existing fleets or build or acquire new fleets. For example, between December 8, 2017 and December 10, 2017, we placed orders for an aggregate of approximately 150,000 newbuild hydraulic horsepower representing three additional hydraulic fracturing fleets, with anticipated capital expenditures for the three fleets of approximately $115.0 million. Such demands on our capital or reductions in demand for our hydraulic fracturing fleets and other completion service related equipment and the increase in cost to maintain labor necessary for such maintenance and improvement, in each case, could have a material adverse effect on our business, liquidity position, financial condition, prospects and results of operations and may increase the cost to make our inactive fleets operational.

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Until recently, we were dependent on a few customers in a single industry. The loss of one or more significant customers could adversely affect our financial condition, prospects and results of operations.
Our customers are engaged in the oil and natural gas E&P business in the U.S. Historically, we have been dependent upon a few customers for a significant portion of our revenues. For the year ended December 31, 2017, no customer represented more than 10% of our consolidated revenue. For the year ended December 31, 2016, three customers, Shell Exploration & Production, XTO Energy and Seneca Resources Corporation, individually represented more than 10% of our consolidated revenue. For the year ended December 31, 2015, four customers, EQT Production Company, XTO Energy, Shell Exploration & Production and Southwestern Energy Company, individually represented more than 10% of our consolidated revenue.
Our business, financial condition, prospects and results of operations could be materially adversely affected if one or more of our significant customers ceases to engage us for our services on favorable terms or at all or fails to pay or delays in paying us significant amounts of our outstanding receivables. Although we do have contracts for multiple projects with certain of our customers, most of our services are provided on a project-by-project basis.
Additionally, the E&P industry is characterized by frequent consolidation activity. Changes in ownership of our customers may result in the loss of, or reduction in, business from those customers, which could materially and adversely affect our business, financial condition, prospects and results of operations.
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, financial condition, prospects and/or results of operations.
Our commitments under supply agreements could exceed our requirements, and our reliance on suppliers exposes us to risks including price, timing of delivery and quality of products and services upon which our business relies.
We have purchase commitments with certain vendors to supply a majority of the proppant used in our operations. Some of these agreements are take-or-pay agreements with minimum purchase obligations. If demand for our hydraulic fracturing services decreases from current levels, demand for the raw materials and products we supply as part of these services will also decrease. If demand decreases enough, we could have contractual minimum commitments that exceed the required amount of goods we need to supply to our customers. In this instance, we could be required to purchase goods that we do not have a present need for, pay for goods that we do not take delivery of or pay prices in excess of market prices at the time of purchase. Additionally, our reliance on outside suppliers for some of the key materials and equipment we use in providing our services involves risks, including limited control over the price, timely delivery availability and quality of such materials or equipment. In addition to continued growth and demand for sand, some transitory factors that also can potentially affect timely delivery and availability of sand include inclement weather, flooding impacts, rail-related output constraints and delays on opening new mine sources.
Unexpected and immediate changes in the availability and pricing of raw materials, or the loss of or interruption in operations of one or more of our suppliers, could have a material adverse effect on our results of operations, prospects and financial condition.
Raw materials essential to our business are normally readily available. However, high levels of demand for raw materials, such as gels, guar, proppant and hydrochloric acid, have triggered constraints in the supply chain of those raw materials and could dramatically increase the prices of such raw materials. For example, during 2012,

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companies in our industry experienced a shortage of guar, which is a key ingredient in fracturing fluids. This shortage resulted in an unexpected and immediate increase in the price of guar. During 2008, our industry faced sporadic proppant shortages requiring work stoppages, which adversely impacted the operating results of several competitors. An increase in the cost of proppant as a result of increased demand or a decrease in the number of proppant providers could increase our cost of an essential raw material in hydraulic stimulation and have a material adverse effect on our business, operations, prospects and financial condition. We may not be able to mitigate any future shortages of raw materials.
New technology may cause us to become less competitive.
The oilfield services industry is subject to the introduction of new drilling and completion techniques and services using new technologies, some of which may be subject to patent or other intellectual property protections. Although we believe our equipment and processes currently give us a competitive advantage, as competitors and others use or develop new or comparable technologies in the future, we may lose market share or be placed at a competitive disadvantage. Further, we may face competitive pressure to develop, implement or acquire certain new technologies at a substantial cost. Some of our competitors have greater financial, technical and personnel resources that may allow them to enjoy technological advantages and develop and implement new products on a timely basis or at an acceptable cost. We cannot be certain that we will be able to develop and implement new technologies or products on a timely basis or at an acceptable cost. Limits on our ability to develop, effectively use and implement new and emerging technologies may have a material adverse effect on our business, financial condition, prospects or results of operations.
Competition among oilfield service and equipment providers is affected by each provider’s reputation for safety and quality.
Our activities are subject to a wide range of national, state and local occupational health and safety laws and regulations. In addition, customers maintain their own compliance and reporting requirements. Failure to comply with these health and safety laws and regulations, or failure to comply with our customers’ compliance or reporting requirements, could tarnish our reputation for safety and quality and have a material adverse effect on our competitive position.
Oilfield 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 oilfield anti-indemnity acts may restrict or void a party’s indemnification of us, which could have a material adverse effect on our business, financial condition, prospects and results of operations.
We are subject to federal, state and local laws and regulations regarding issues of health, safety and protection of the environment. Under these laws and regulations, we may become liable for penalties, damages or costs of remediation or other corrective measures. Any changes in laws or government regulations could increase our costs of doing business.
Our operations are subject to stringent federal, state, local and tribal laws and regulations relating to, among other things, protection of natural resources, clean air and drinking water, wetlands, endangered species, greenhouse gasses, nonattainment areas, the environment, health and safety, chemical use and storage, waste management, waste disposal and transportation of waste and other hazardous and nonhazardous materials. Our operations involve risks of environmental liability, including leakage from an operator’s casing during our operations or accidental spills onto or into surface or subsurface soils, surface water or groundwater. Some environmental laws and regulations

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may impose strict liability, joint and several liability, or both. In some situations, we could be exposed to liability as a result of our conduct that was lawful at the time it occurred or the conduct of, or conditions caused by, third parties without regard to whether we caused or contributed to the conditions. Additionally, environmental concerns, including clean air, drinking water contamination and seismic activity, have prompted investigations that could lead to the enactment of regulations, limitations, restrictions or moratoria that could potentially have a material adverse impact on our business. Actions arising under these laws and regulations could result in the shutdown of our operations, fines and penalties (administrative, civil or criminal), revocations of permits to conduct business, expenditures for remediation or other corrective measures and/or claims for liability for property damage, exposure to hazardous materials, exposure to hazardous waste, nuisance or personal injuries. Sanctions for noncompliance with applicable environmental laws and regulations may also include the assessment of administrative, civil or criminal penalties, revocation of permits and temporary or permanent cessation of operations in a particular location and issuance of corrective action orders. Such claims or sanctions and related costs could cause us to incur substantial costs or losses and could have a material adverse effect on our business, financial condition, prospects and results of operations. Additionally, an increase in regulatory requirements, limitations, restrictions or moratoria on oil and natural gas exploration and completion activities at a federal, state or local level could significantly delay or interrupt our operations, limit the amount of work we can perform, increase our costs of compliance, or increase the cost of our services, thereby possibly having a material adverse impact on our financial condition.
If we do not perform in accordance with government, industry, customer or our own health, safety and environmental standards, we could lose business from our customers, many of whom have an increased focus on environmental and safety issues.
We are subject to the EPA, U.S. Department of Transportation, U.S. Nuclear Regulation Commission, OSHA and state regulatory agencies that regulate operations to prevent air, soil and water pollution. The energy extraction sector is one of the sectors designated for increased enforcement by the EPA, which will continue to regulate our industry in the years to come, potentially resulting in additional regulations that could have a material adverse impact on our business, prospects or financial condition.
The EPA regulates air emissions from all engines, including off-road diesel engines that are used by us to power equipment in the field. Under these U.S. emission control regulations, we could be limited in the number of certain off-road diesel engines we can purchase. Further, the emission control and fuel quality regulations could result in increased costs.
Laws and regulations protecting the environment generally have become more stringent over time, and we expect them to continue to do so. This could lead to material increases in our costs, and liability exposure, for future environmental compliance and remediation. Additionally, if we expand the size or scope of our operations, we could be subject to existing regulations that are more stringent than the requirements under which we are currently allowed to operate or require additional authorizations to continue operations. Compliance with this additional regulatory burden could increase our operating or other costs.
Federal, state and local legislative and regulatory initiatives relating to hydraulic fracturing could prohibit, restrict or limit hydraulic fracturing operations, could increase our operating costs or could result in the disclosure of proprietary information resulting in competitive harm.
During recent sessions of the U.S. Congress, several pieces of legislation were introduced in the U.S. Senate and House of Representatives for the purpose of amending environmental laws such as the Clean Air Act, the SDWA and the Toxic Substance Control Act with respect to activities associated with extraction and energy production industries, especially the oil and gas industry. Furthermore, various items of legislation and rulemaking have been proposed that would regulate or prevent federal regulation of hydraulic fracturing on federally owned land. Proposed rulemaking from the EPA and OSHA, such as the proposed regulation relating to respirable silica sand, could increase our regulatory requirements, which could increase our costs of compliance or increase the costs of our services, thereby possibly having a material adverse impact on our business and results of operations.

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If the EPA or another federal or state-level agency asserts jurisdiction over certain aspects of hydraulic fracturing operations, an additional level of regulation established at the federal or state level could lead to operational delays and increase our costs. The EPA recently issued a study of the potential impacts of hydraulic fracturing on drinking water and groundwater. The EPA report states that there is scientific evidence that hydraulic fracturing activities can impact drinking resources under some circumstances, and identifies certain conditions in which the EPA believes the impact of such activities on drinking water and groundwater can be more frequent or severe. The EPA study could spur further initiatives to regulate hydraulic fracturing under the SDWA or otherwise. Many regulatory and legislative bodies routinely evaluate the adequacy and effectiveness of laws and regulations affecting the oil and gas industry. As a result, state legislatures, state regulatory agencies and local municipalities may consider legislation, regulations or ordinances, respectively, that could affect all aspects of the oil and natural gas industry and occasionally take action to restrict or further regulate hydraulic fracturing operations. At this time, it is not possible to estimate the potential impact on our business of these state and municipal actions or the enactment of additional federal or state legislation or regulations affecting hydraulic fracturing. Compliance, stricter regulations or the consequences of any failure to comply by us could have a material adverse effect on our business, financial condition, prospects and results of operations.
Many states in which we operate require the disclosure of some or all of the chemicals used in our hydraulic fracturing operations. Certain aspects of one or more of these chemicals may be considered proprietary by us or our chemical suppliers. Disclosure of our proprietary chemical information to third parties or to the public, even if inadvertent, could diminish the value of our trade secrets or those of our chemical suppliers and could result in competitive harm to us, which could have an adverse impact on our business, financial condition, prospects and results of operations.
We are also aware that some states, counties and municipalities have enacted or are considering moratoria on hydraulic fracturing. For example, New York and Vermont have banned or are in the process of banning the use of high volume hydraulic fracturing. Alternatively, some municipalities are or have considered zoning and other ordinances, the conditions of which could impose a de facto ban on drilling and/or hydraulic fracturing operations. Further, some states, counties and municipalities are closely examining water use issues, such as permit and disposal options for processed water, which could have a material adverse impact on our financial condition, prospects and results of operations if such additional permitting requirements are imposed upon our industry. Additionally, our business could be affected by a moratorium or increased regulation of companies in our supply chain, such as sand mining by our proppant suppliers, which could limit our access to supplies and increase the costs of our raw materials. At this time, it is not possible to estimate how these various restrictions could affect our ongoing operations. For more information, see “Item 1. Business—Environmental regulation.”
Existing or future laws and regulations related to greenhouse gases and climate change could have a negative impact on our business and may result in additional compliance obligations with respect to the release, capture and use of carbon dioxide that could have a material adverse effect on our business, results of operations, prospects and financial condition.
Changes in environmental requirements related to greenhouse gases and climate change may negatively impact demand for our services. For example, oil and natural gas exploration and production may decline as a result of environmental requirements, including land use policies responsive to environmental concerns. Federal, state and local agencies have been evaluating climate-related legislation and other regulatory initiatives that would restrict emissions of greenhouse gases in areas in which we conduct business. Because our business depends on the level of activity in the oil and natural gas industry, existing or future laws and regulations related to greenhouse gases and climate change, including incentives to conserve energy or use alternative energy sources, could have a negative impact on our business if such laws or regulations reduce demand for oil and natural gas. Likewise, such restrictions may result in additional compliance obligations with respect to the release, capture, sequestration and use of carbon dioxide that could have a material adverse effect on our business, results of operations, prospects and financial condition.

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Comprehensive tax reform bills could adversely affect our business and financial condition.
The U.S. government has enacted comprehensive tax legislation that includes significant changes to the taxation of business entities. These changes include, among others, a permanent reduction to the corporate income tax rate, additional limitations on the tax deductibility of interest, immediate deductions for certain new investments instead of deductions for depreciation expense over time and modification or repeal of many business deductions and credits. Notwithstanding the reduction in the corporate income tax rate, the overall impact of this tax reform is uncertain, and our business and financial condition could be adversely affected.
We use intellectual property relating to hydraulic fracturing fluids and electronic pump control which is subject to non-exclusive license arrangements and may be licensed to our competitors, which could adversely affect our business.
Trican has licensed our use of certain of its hydraulic fracturing fluids and electronic pump control technology under non-exclusive agreements. Accordingly, Trican has the right to license the same technologies and fracturing fluids that we use in our operations to our competitors, which could adversely affect our business. The rights obtained under this license may be shared with others who have been granted a similar non-exclusive license. As a result, the non-exclusive nature of this license may lead to conflicts between us and others granted similar rights.
If we are unable to fully protect our intellectual property rights, 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 also cannot assure you that any patents we may obtain in the future would provide us with any significant commercial benefit or would allow us to prevent our competitors from employing comparable technologies or processes.
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 sales and profitability.
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 U.S. Department of Transportation 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 and limits on vehicle weight and size. As 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. Our operations, including routing and weight restrictions, could be affected by road construction, road repairs, detours and state and local regulations and ordinances restricting access to certain roads. 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

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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 may be unable to employ a sufficient number of key employees, technical personnel and other skilled or qualified workers.
The delivery of our services and products requires personnel with specialized skills and experience who can perform physically demanding work. As a result of the volatility in the energy service industry and the demanding nature of the work, workers may choose to pursue employment with our competitors or in fields that offer a more desirable work environment. Furthermore, 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, without first obtaining a required work authorization from the U.S. Department of Homeland Security or similar government agency. Our ability to be productive and profitable will depend upon our ability to employ and retain skilled workers. In addition, our ability to further expand our operations according to geographic demand for our services depends in part on our ability to relocate or increase the size of our skilled labor force. The demand for skilled workers in our areas of operations can be high, the supply may be limited and we may be unable to relocate our employees from areas of lower utilization to areas of higher demand. A significant increase 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. Further, a significant decrease in the wages paid by us or our competitors as a result of reduced industry demand could result in a reduction of the available skilled labor force, and there is no assurance that the availability of skilled labor will improve following a subsequent increase in demand for our services or an increase in wage rates. If any of these events were to occur, our capacity and profitability could be diminished and our growth potential could be impaired.
We depend heavily on the efforts of executive officers, managers and other key employees to manage our operations. The unexpected loss or unavailability of key members of management or technical personnel may have a material adverse effect on our business, financial condition, prospects or results of operations.
Adverse weather conditions could impact demand for our services or materially impact our costs.
Our business could be materially adversely affected by adverse weather conditions. For example, unusually warm winters could adversely affect the demand for our services by decreasing the demand for natural gas. In addition, unusually cold winters and other weather conditions could adversely affect our ability to perform our services due to delays in the delivery of products that we need to provide our services. For example, recent weather-induced rail congestion, combined with flooding impacts at suppliers’ mines, has contributed to a reduction in the availability of sands used in our operations. Our operations in arid regions can also be affected by droughts and limited access to water used in our hydraulic fracturing operations. Adverse weather can also directly impede our own operations. Repercussions of adverse weather conditions may include:
curtailment of services;
weather-related damage to facilities and equipment, resulting in delays in operations;
inability to deliver equipment, personnel and products to job sites in accordance with contract schedules; and
loss of productivity.
Delays in obtaining, or inability to obtain or renew, permits or authorizations by our customers for their operations or by us for our operations could impair our business.
In most states, our customers are required to obtain permits or authorizations from one or more governmental agencies or other third parties to perform drilling and completion activities, including hydraulic

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fracturing. Such permits or approvals are typically required by state agencies, but can also be required by federal and local governmental agencies or other third parties. The requirements for such permits or authorizations vary depending on the location where such drilling and completion activities will be conducted. As with most permitting and authorization processes, there is a degree of uncertainty as to whether a permit will be granted, the time it will take for a permit or approval to be issued and the conditions which may be imposed in connection with the granting of the permit. In some jurisdictions, such as New York State and within the jurisdiction of the Delaware River Basin Commission, certain regulatory authorities have delayed or suspended the issuance of permits or authorizations while the potential environmental impacts associated with issuing such permits can be studied and appropriate mitigation measures evaluated. In Texas, rural water districts have begun to impose restrictions on water use and may require permits for water used in drilling and completion activities. Permitting, authorization or renewal delays, the inability to obtain new permits or the revocation of current permits could cause a loss of revenue and potentially have a materially adverse effect on our business, financial condition, prospects or results of operations.
We are also required to obtain federal, state, local and/or third-party permits and authorizations in some jurisdictions in connection with our wireline services. These permits, when required, impose certain conditions on our operations. Any changes in these requirements could have a material adverse effect on our business, financial condition, prospects and results of operations.
We may not be successful in identifying and making acquisitions.
Part of our strategy to expand our geographic scope and customer relationships, increase our access to technology and to grow our business is dependent on our ability to make acquisitions that result in accretive revenues and earnings. We may be unable to make accretive acquisitions or realize expected benefits of any acquisitions for any of the following reasons:
failure to identify attractive targets;
incorrect assumptions regarding the future results of acquired operations or assets or expected cost reductions or other synergies expected to be realized as a result of acquiring operations or assets;
failure to obtain financing on acceptable terms or at all;
restrictions in our debt agreements;
failure to successfully integrate the operations or management of any acquired operations or assets;
failure to retain or attract key employees; and
diversion of management’s attention from existing operations or other priorities.
Our acquisition strategy requires that we successfully integrate acquired companies into our business practices as well as our procurement, management and enterprise-wide information technology systems. We may not be successful in implementing our business practices at acquired companies, and our acquisitions could face difficulty in transitioning from their previous information technology systems to our own. Furthermore, unexpected costs and challenges may arise whenever businesses with different operations of management are combined. Any such difficulties, or increased costs associated with such integration, could affect our business, financial performance and operations.
If we are unable to identify, complete and integrate acquisitions, it could have a material adverse effect on our growth strategy, business, financial condition, prospects and results of operations.

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Integrating acquisitions may be time-consuming and create costs that could reduce our net income and cash flows.
Part of our strategy includes pursuing acquisitions that we believe will be accretive to our business. If we consummate an acquisition, the process of integrating the acquired business may be complex and time consuming, may be disruptive to the business and may cause an interruption of, or a distraction of management’s attention from, the business as a result of a number of obstacles, including, but not limited to:
a failure of our due diligence process to identify significant risks or issues;
the loss of customers of the acquired company or our company;
negative impact on the brands or banners of the acquired company or our company;
a failure to maintain or improve the quality of customer service;
difficulties assimilating the operations and personnel of the acquired company;
our inability to retain key personnel of the acquired company;
the incurrence of unexpected expenses and working capital requirements;
our inability to achieve the financial and strategic goals, including synergies, for the combined businesses;
difficulty in maintaining internal controls, procedures and policies;
mistaken assumptions about the overall costs of equity or debt; and
unforeseen difficulties operating in new product areas or new geographic areas.
Any of the foregoing obstacles, or a combination of them, could decrease gross profit margins or increase selling, general and administrative expenses in absolute terms and/or as a percentage of net sales, which could in turn negatively impact our net income and cash flows.
We may not be able to consummate acquisitions in the future on terms acceptable to us, or at all. In addition, future acquisitions are accompanied by the risk that the obligations and liabilities of an acquired company may not be adequately reflected in the historical financial statements of that company and the risk that those historical financial statements may be based on assumptions which are incorrect or inconsistent with our assumptions or approach to accounting policies. Any of these material obligations, liabilities or incorrect or inconsistent assumptions could adversely impact our results of operations, prospects and financial condition.
Our historical financial statements may not be indicative of future performance.
In light of the Trican transaction completed in March 2016 and the RockPile Acquisition completed in July 2017, our operating results only reflect the impact of the acquisition for dates after the closing of the transaction, and, therefore, comparisons with prior periods are difficult. As a result, our limited historical financial performance as the owner of the Acquired Trican Operations and RockPile may make it difficult for stockholders to evaluate our business and results of operations to date and to assess our future prospects and viability.
Furthermore, as a result of the implementation of new business initiatives and strategies following the completion of the Trican and RockPile transactions, our historical results of operations are not necessarily indicative of our ongoing operations and the operating results to be expected in the future.

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Risks Related to Owning Our Indebtedness
Our substantial level of indebtedness could adversely affect our financial condition and prevent us from fulfilling our obligations under our indebtedness.
We have a significant amount of indebtedness. As of December 31, 2017, we had $275.1 million of debt outstanding, net of discounts and deferred financing costs (not including capital lease obligations). After giving effect to our borrowing base, we had approximately $199.7 million of availability under our 2017 ABL Facility.
Our substantial indebtedness could have important consequences to you. For example, it could:
adversely affect the market price of our common stock;
increase our vulnerability to interest rate increases and general adverse economic and industry conditions;
require us to dedicate a substantial portion of our cash flow from operations to payments on our indebtedness, thereby reducing the availability of our cash flow to fund working capital, capital expenditures and other general corporate purposes, including acquisitions;
limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate;
limit our ability to obtain additional financing on satisfactory terms to fund our working capital requirements, capital expenditures, acquisitions, investments, debt service requirements and other general corporate requirements; and
place us at a competitive disadvantage compared to our competitors that have less debt.
In addition, we cannot assure you that we will be able to refinance any of our debt or that we will be able to refinance our debt on commercially reasonable terms. If we were unable to make payments or refinance our debt or obtain new financing under these circumstances, we would have to consider other options, such as:
sales of assets;
sales of equity; or
negotiations with our lenders to restructure the applicable debt.
Our debt instruments may restrict, or market or business conditions may limit, our ability to use some of our options.
Despite our significant indebtedness levels, we may still be able to incur additional debt, which could further exacerbate the risks associated with our substantial leverage.
We and our subsidiaries may be able to incur additional indebtedness in the future. The terms of the credit agreements that govern the 2017 ABL Facility (as defined herein) and the 2017 Term Loan Facility (as defined herein and, together with the 2017 ABL Facility, the “Senior Secured Debt Facilities”) permit us to incur additional indebtedness, subject to certain limitations. If new indebtedness is added to our and our subsidiaries’ current debt levels, the related risks that we and they now face would intensify. See Part II, “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations–Principal Debt Agreements” for further details.

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The agreements governing our indebtedness contain operating covenants and restrictions that limit our operations and could lead to adverse consequences if we fail to comply with them.
The agreements governing our indebtedness contain certain operating covenants and other restrictions relating to, among other things, limitations on indebtedness (including guarantees of additional indebtedness) and liens, mergers, consolidations and dissolutions, sales of assets, investments and acquisitions, dividends and other restricted payments, repurchase of shares of capital stock and options to purchase shares of capital stock and certain transactions with affiliates. In addition, our Senior Secured Debt Facilities include certain financial covenants.
The restrictions in the agreements governing our indebtedness may prevent us from taking actions that we believe would be in the best interest of our business, and may make it difficult for us to successfully execute our business strategy or effectively compete with companies that are not similarly restricted. We may also incur future debt obligations that might subject us to additional restrictive covenants that could affect our financial and operational flexibility.
Failure to comply with these financial and operating covenants could result from, among other things, changes in our results of operations, the incurrence of additional indebtedness, the pricing of our products, our success at implementing cost reduction initiatives, our ability to successfully implement our overall business strategy or changes in general economic conditions, which may be beyond our control. The breach of any of these covenants or restrictions could result in a default under the agreements that govern these facilities that would permit the lenders to declare all amounts outstanding thereunder to be due and payable, together with accrued and unpaid interest. If we are unable to repay such amounts, lenders having secured obligations could proceed against the collateral securing these obligations. The collateral includes the capital stock of our domestic subsidiaries and substantially all of our and our subsidiaries’ other tangible and intangible assets, subject in each case to certain exceptions. This could have serious consequences on our financial condition and results of operations and could cause us to become bankrupt or otherwise insolvent. In addition, these covenants may restrict our ability to engage in transactions that we believe would otherwise be in the best interests of our business and stockholders.
See Part II, “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations–Principal Debt Agreements” for further details.
Substantially all of our debt is variable rate and increases in interest rates could negatively affect our financing costs and our ability to access capital.
We have exposure to future interest rates based on the variable rate debt under the Senior Secured Debt Facilities and to the extent we raise additional debt in the capital markets to meet maturing debt obligations, to fund our capital expenditures and working capital needs and to finance future acquisitions. Daily working capital requirements are typically financed with operational cash flow and through borrowings under our 2017 ABL Facility, if needed. The interest rate on these borrowing arrangements is generally determined from the inter-bank offering rate at the borrowing date plus a pre-set margin. Although we employ risk management techniques to hedge against interest rate volatility, significant and sustained increases in market interest rates could materially increase our financing costs and negatively impact our reported results.
Risks Related to Owning Our Common Stock
The price of our common stock may be volatile or may decline regardless of our operating performance, and you may not be able to resell your shares at or above the public offering price.
The market price for our common stock is volatile. In addition, the market price of our common stock may fluctuate significantly in response to a number of factors, most of which we cannot control, including
the failure of securities analysts to cover, or continue to cover, our common stock, or changes in financial estimates by analysts;
changes in, or investors’ perception of, the hydraulic fracturing industry;

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the activities of competitors;
future issuances and sales of our common stock, including in connection with acquisitions;
our quarterly or annual earnings or those of other companies in our industry;
the public’s reaction to our press releases, our other public announcements and our filings with the SEC;
regulatory or legal developments in the United States;
litigation involving us, our industry, or both; and
general economic conditions.
As a result of these factors, you may not be able to resell your shares of our common stock at or above the offering price. In addition, the stock market often experiences extreme price and volume fluctuations that have often been unrelated or disproportionate to the operating performance of a particular company. These broad market fluctuations and industry factors may materially reduce the market price of our common stock, regardless of our operating performance.
Keane Investor and our Sponsor control us and may have conflicts of interest with other stockholders in the future.
Keane Investor controls approximately 50.7% of our common stock. As a result, Keane Investor is able to control the election of our directors, determine our corporate and management policies and determine, without the consent of our other stockholders, the outcome of any corporate transaction or other matter submitted to our stockholders for approval, including potential mergers or acquisitions, asset sales and other significant corporate transactions. Seven of our 12 directors are employees of, appointees of, or advisors to, members of Cerberus, as described under Part III, “Item 10. Directors, Officers and Corporate Governance.” Cerberus, through Keane Investor, will also have sufficient voting power to amend our organizational documents. The interests of Cerberus may not coincide with the interests of other holders of our common stock. Additionally, Cerberus is in the business of making investments in companies and may, from time to time, acquire and hold interests in businesses that compete directly or indirectly with us. Cerberus may also pursue, for its own members’ accounts, acquisition opportunities that may be complementary to our business, and as a result, those acquisition opportunities may not be available to us. So long as Cerberus continues to own a significant amount of the outstanding shares of our common stock through Keane Investor, Cerberus will continue to be able to strongly influence or effectively control our decisions, including potential mergers or acquisitions, asset sales and other significant corporate transactions.
We are restricted from competing with Trican in the oilfield services business in Canada, which may adversely affect our access to, or our ability to expand within, the Canadian market.
We agreed to a non-competition provision with Trican as part our acquisition of the Acquired Trican Operations, pursuant to which, subject to certain limited exceptions, we may not compete, directly or indirectly, with Trican in Canada in the oilfield services business through March 16, 2018. Subject to certain limited exceptions, we also may not own an interest in any entity that competes directly or indirectly with Trican in Canada, other than with respect to any industrial services or completion tools business or certain interests in companies with limited revenues derived from Canadian operations. These restrictions may adversely affect our access to or ability to expand within the Canadian market. Additionally, Trican has an ownership interest in Keane Investor, and conflicts of interest may therefore arise between Trican and our other shareholders relating to opportunities to enter into or expand within the Canadian oilfield business.

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We will continue to incur increased costs as a result of becoming a publicly traded company.
As a newly public company, we are subject to the reporting requirements of the Exchange Act, the Sarbanes-Oxley Act of 2002, as amended, the Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010 and the rules and regulations of the New York Stock Exchange (“NYSE”). Being subject to these rules and regulations will result in additional legal, accounting and financial compliance costs, will make some activities more difficult, time-consuming and costly and may also place significant strain on management, systems and resources.
These laws and regulations also could make it more difficult or costly for us to obtain certain types of insurance, including director and officer liability insurance, and we may be forced to accept reduced policy limits and coverage or incur substantially higher costs to obtain the same or similar coverage. These laws and regulations could also make it more difficult for us to attract and retain qualified persons to serve on our board of directors or our board committees or as our executive officers. Furthermore, if we are unable to satisfy our obligations as a public company, we could be subject to delisting of our common stock, fines, sanctions and other regulatory actions and potentially civil litigation.
We are a “controlled company” within the meaning of the NYSE rules and, as a result, qualify for, and intend to rely on, exemptions from certain corporate governance requirements. Our stockholders will not have the same protections afforded to stockholders of companies that are subject to such requirements.
Keane Investor controls a majority of our outstanding common stock. As a result, we are a “controlled company” within the meaning of the NYSE rules. Under the NYSE rules, a company of which more than 50% of the voting power is held by an individual, group or another company is a “controlled company” and may elect not to comply with certain corporate governance requirements, including:
•    the requirement that a majority of the board of directors consist of independent directors;
•    the requirement that we have a nominating and corporate governance committee that is composed entirely of independent directors with a written charter addressing the committee’s purpose and responsibilities; and
•    the requirement that we have a compensation committee that is composed entirely of independent directors with a written charter addressing the committee’s purpose and responsibilities.
We currently utilize, and intend to continue to utilize these exemptions. As a result, we do not have a majority of independent directors nor do our nominating and corporate governance and compensation committees consist entirely of independent directors. Accordingly, our stockholders will not have the same protections afforded to stockholders of companies that are subject to all of the NYSE corporate governance requirements.
Provisions in our charter documents, certain agreements governing our indebtedness, our Stockholders’ Agreement and Delaware law could make an acquisition of us more difficult and may prevent attempts by our stockholders to replace or remove our current management, even if beneficial to our stockholders.
Provisions in our certificate of incorporation and our bylaws, may discourage, delay or prevent a merger, acquisition or other change in control that some stockholders may consider favorable, including transactions in which our stockholders might otherwise receive a premium for their shares of our common stock. These provisions could also limit the price that investors might be willing to pay in the future for shares of our common stock, possibly depressing the market price of our common stock.
In addition, these provisions may frustrate or prevent any attempts by our stockholders to replace members of our board of directors. Because our board of directors is responsible for appointing the members of our management team, these provisions could in turn affect any attempt by our stockholders to replace members of our management team. Examples of such provisions are as follows:
•    from and after such date that Keane Investor and its respective Affiliates (as defined in Rule 12b-2 of the Exchange Act, or any person who is an express assignee or designee of Keane Investor’s respective rights under our

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certificate of incorporation (and such assignee’s or designee’s Affiliates) (of these entities, the entity that is the beneficial owner of the largest number of shares is referred to as the “Designated Controlling Stockholder”) ceases to own, in the aggregate, at least 50% of the then-outstanding shares of our common stock (the “50% Trigger Date”), the authorized number of our directors may be increased or decreased only by the affirmative vote of two-thirds of the then-outstanding shares of our common stock or by resolution of our board of directors;
•    prior to the 50% Trigger Date, only our board of directors and the Designated Controlling Stockholder are expressly authorized to make, alter or repeal our bylaws and, from and after the 50% Trigger Date, our stockholders may only amend our bylaws with the approval of at least two-thirds of all of the outstanding shares of our capital stock entitled to vote;
•    from and after the 50% Trigger Date, the manner in which stockholders can remove directors from the board will be limited;
•    from and after the 50% Trigger Date, stockholder actions must be effected at a duly called stockholder meeting and actions by our stockholders by written consent will be prohibited;
•    from and after such date that Keane Investor and its respective Affiliates (or any person who is an express assignee or designee of Keane Investor’s respective rights under our certificate of incorporation (and such assignee’s or designee’s Affiliates)) ceases to own, in the aggregate, at least 35% of the then-outstanding shares of our common stock (the “35% Trigger Date”), advance notice requirements for stockholder proposals that can be acted on at stockholder meetings and nominations to our board of directors will be established;
•    limits on who may call stockholder meetings;
•    requirements on any stockholder (or group of stockholders acting in concert), other than, prior to the 35% Trigger Date, the Designated Controlling Stockholder, who seeks to transact business at a meeting or nominate directors for election to submit a list of derivative interests in any of our company’s securities, including any short interests and synthetic equity interests held by such proposing stockholder;
•    requirements on any stockholder (or group of stockholders acting in concert) who seeks to nominate directors for election to submit a list of “related party transactions” with the proposed nominee(s) (as if such nominating person were a registrant pursuant to Item 404 of Regulation S-K, and the proposed nominee was an executive officer or director of the “registrant”); and
•    our board of directors is authorized to issue preferred stock without stockholder approval, which could be used to institute a “poison pill” that would work to dilute the stock ownership of a potential hostile acquirer, effectively preventing acquisitions that have not been approved by our board of directors.
Our certificate of incorporation authorizes our board of directors to issue up to 50,000,000 shares of preferred stock. The preferred stock may be issued in one or more series, the terms of which may be determined by our board of directors at the time of issuance or fixed by resolution without further action by the stockholders. These terms may include voting rights, preferences as to dividends and liquidation, conversion rights, redemption rights and sinking fund provisions. The issuance of preferred stock could diminish the rights of holders of our common stock, and, therefore, could reduce the value of our common stock. In addition, specific rights granted to holders of preferred stock could be used to restrict our ability to merge with, or sell assets to, a third party. The ability of our board of directors to issue preferred stock could delay, discourage, prevent or make it more difficult or costly to acquire or effect a change in control, thereby preserving the current stockholders’ control.
In addition, under the agreements governing the Senior Secured Debt Facilities, a change in control may lead the lenders and/or holders to exercise remedies such as acceleration of the obligations thereunder, termination of their commitments to fund additional advances and collection against the collateral securing such obligations.
Pursuant to a limited liability company agreement entered into by Cerberus and certain other entities and individuals who agreed to co-invest with Cerberus through Keane Investor (the “Keane Investor LLC Agreement”),

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such appointees shall be selected by Keane Investor’s board of managers so long as Keane is a controlled company under the applicable rules of the NYSE. See Part III, “Item 13. Certain Relationships and Related-Party Transactions and Director Independence—Keane Investor Limited Liability Company Agreement.”
Our Stockholders’ Agreement (as defined herein) provides that, except as otherwise required by applicable law, from the date on which (a) Keane is no longer a controlled company under the applicable rules of the NYSE but prior to the 35% Trigger Date, Keane Investor has the right to designate a number of individuals who satisfy the Director Requirements (as defined herein) equal to one director fewer than 50% of our board of directors at any time and shall cause its directors appointed to our board of directors to vote in favor of maintaining an 11-person board of directors unless the management board of Keane Investor otherwise agrees by the affirmative vote of 80% of the management board of Keane Investor; (b) a Holder (as defined herein) has beneficial ownership of at least 20% but less than 35% of our outstanding common stock, the Holder will have the right to designate a number of individuals who satisfy the Director Requirements equal to the greater of three or 25% of the size of our board of directors at any time (rounded up to the next whole number); (c) a Holder has beneficial ownership of at least 15% but less than 20% of our outstanding common stock, the Holder will have the right to designate the greater of two or 15% of the size of our board of directors at any time (rounded up to the next whole number); and (d) a Holder has beneficial ownership of at least 10% but less than 15% of our outstanding common stock, it will have the right to designate one individual who satisfies the Director Requirements. The ability of Keane Investor or a Holder to appoint one or more directors could make an acquisition of us more difficult and may prevent attempts by our stockholders to replace or remove our current management, even if beneficial to our stockholders.
Our certificate of incorporation and bylaws designate 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 stockholders, which could limit our stockholders’ ability to obtain a favorable judicial forum for disputes with us or our directors, officers or other employees.
Our 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 will be the exclusive forum for: (a) any derivative action or proceeding brought on our behalf; (b) any action asserting a claim for breach of a fiduciary duty owed by any of our directors, officers, employees or agents to us or our stockholders; (c) any action asserting a claim arising pursuant to any provision of the Delaware General Corporation Law (the “DGCL”), our certificate of incorporation or our bylaws; or (d) any action asserting a claim governed by the internal affairs doctrine. Any person or entity purchasing or otherwise acquiring any interest in shares of our capital stock is deemed to have received notice of and consented to the foregoing provisions. This choice of forum provision may limit a stockholder’s ability to bring a claim in a judicial forum that it finds more favorable for disputes with us or our directors, officers or other employees, which may discourage such lawsuits against us and our directors, officers and employees. Alternatively, if a court were to find this choice of forum provision inapplicable to, or unenforceable in respect of, one or more of the specified types of actions or proceedings, we may incur additional costs associated with resolving such matters in other jurisdictions, which could adversely affect our business, financial condition, prospects or results of operations.
If a substantial number of shares becomes available for sale and are sold in a short period of time, the market price of our common stock could decline and our stockholders may be diluted.
If Keane Investor, WDE RockPile Aggregate, LLC and three other individuals who acquired shares of our common stock in the RockPile acquisition (together with WDE RockPile Aggregate, LLC, the “RockPile Holders”) sell substantial amounts of our common stock in the public market, the market price of our common stock could decrease. The perception in the public market that Keane Investor or the RockPile Holders might sell shares of common stock could also create a perceived overhang and depress our market price. 112,243,769 shares of common stock are outstanding of which 65,579,625 shares are held by Keane Investor and the RockPile Holders.
Keane Investor and our executive officers and directors, but not the RockPile Holders, have previously agreed with certain underwriters to a “lock-up” period, meaning that such parties may not, subject to certain exceptions, sell any of their existing shares of our common stock without the prior written consent of representatives of the underwriters until at least April 17, 2018. When the lock-up agreements expire, these shares will become

30



eligible for sale, The market price for shares of our common stock may drop when the restrictions on resale by Keane Investor lapse.
In addition, Keane Investor and the RockPile Holders have substantial demand and incidental registration rights, as described in Part III, “Item 13. Certain Relationships and Related Party Transactions—Stockholders’ Agreement.”
We may be required to make payments under our contingent value rights agreement with the RockPile Holders.
Subject to the terms and conditions of the Contingent Value Rights Agreement (the "CVR Agreement") by and among the Company, the Principal Seller and Permitted Holders (as defined in the CVR Agreement, the "RockPile Holders") entered into upon consummation of the RockPile acquisition, the RockPile Holders received non-transferable contingent value rights, which collectively entitle the RockPile Holders to receive from the Company, in certain circumstances, an aggregate payment amount of up to $20.0 million. The aggregate payment amount is contingent upon the difference between $19.00 and the trading price of Keane’s common stock in a 30-trading day period prior to April 3, 2018, the nine-month maturity date of the contingent value rights, with such amount to be reduced, in certain circumstances, to the extent the Company shares acquired by the RockPile Holder's in the RockPile acquisition are resold by the RockPile Holders prior to the maturity date. To the extent we are required to make a payment to the RockPile Holders under the CVR Agreement upon maturity, our liquidity may be adversely affected. For additional information on our obligations under the CVR Agreement, see Note (3) Acquisitions of Part II, "Item 8. Financial Statements and Supplemental Data."
If equity research analysts do not publish research or reports about our business or if they issue unfavorable commentary or downgrade our common shares, the market price of our common stock could decline.
The trading market for our common shares likely will be influenced by the research and reports that equity and debt research analysts publish about the industry, us and our business. The market price of our common stock could decline if one or more securities analysts fail to cover our securities, if those analysts downgrade our shares or if those analysts issue a sell recommendation or other unfavorable commentary or cease publishing reports about us or our business. If one or more of the analysts who elect to cover us downgrade our shares, the market price of our common stock would likely decline
Because we do not currently intend to pay dividends, our stockholders may not receive any return on investment unless they sell their common stock for a price greater than that which they paid for it.
We do not currently intend to pay dividends, and our stockholders will not be guaranteed, or have contractual or other rights, to receive dividends. Our board of directors may, in its discretion, modify or repeal our dividend policy. The declaration and payment of dividends depends on various factors, including: our net income, financial condition, cash requirements, future prospects and other factors deemed relevant by our board of directors.
In addition, we are a holding company that does not conduct any business operations of our own. As a result, we are dependent upon cash dividends and distributions and other transfers from our subsidiaries to make dividend payments. Our subsidiaries’ ability to pay dividends is restricted by agreements governing their debt instruments, and may be restricted by agreements governing any of our subsidiaries’ future indebtedness. Furthermore, our subsidiaries are permitted under the terms of their debt agreements to incur additional indebtedness that may severely restrict or prohibit the payment of dividends. See Part II, “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations–Liquidity and Capital Resources.”
Under the DGCL, our board of directors may not authorize payment of a dividend unless it is either paid out of our surplus, as calculated in accordance with the DGCL, or if we do not have a surplus, it is paid out of our net profits for the fiscal year in which the dividend is declared and/or the preceding fiscal year.

31



Our stockholders may be diluted by the future issuance of additional common stock in connection with our equity incentive plans, acquisitions or otherwise.
We have 387,756,231 shares of common stock authorized but unissued under our certificate of incorporation. We will be authorized to issue these shares of common stock and options, rights, warrants and appreciation rights relating to common stock for consideration and on terms and conditions established by our board of directors in its sole discretion, whether in connection with acquisitions or otherwise. We have reserved 7,734,601 shares of our common stock for awards that may be issued under our Equity and Incentive Award Plan. Any common stock that we issue, including under our Equity and Incentive Award Plan or other equity incentive plans that we may adopt in the future, may result in additional dilution to our stockholders.
In the future, we may also issue our securities, including shares of our common stock, in connection with investments or acquisitions. We regularly evaluate potential acquisition opportunities, including ones that would be significant to us, and we are currently participating in processes regarding several potential acquisition opportunities, including ones that would be significant to us. We cannot predict the timing of any contemplated transactions, and none are currently probable, but any pending transaction could be entered into as soon as shortly after the filing of this Annual Report on Form 10-K. The number of shares of our common stock issued in connection with an investment or acquisition could constitute a material portion of our then-outstanding shares of common stock. Any issuance of additional securities in connection with investments or acquisitions may result in additional dilution to our stockholders.


32




Item 1B. Unresolved Staff Comments
None.


33




Item 2. Properties
Properties
Our principal properties include our corporate headquarters, district offices, sales offices and our engineering and technology facility, as well as the hydraulic fracturing units and other equipment and vehicles operating out of these facilities. We believe our facilities are in good condition and suitable for our current operations. Below is a table detailing our properties in the United States as of December 31, 2017:
Location
Own/
Lease
Purpose
Service
Active/
Idle
Size (sqft/acres)
 
 
 
 
 
 
Denver, CO
Lease
Executive / Finance
N/A
Active
19,706 sqft
Houston, TX
Lease
Executive / Finance
N/A
Active
27,700 sqft
Houston, TX
Lease
Executive / Finance
N/A
Active
2,414 sqft
Pittsburgh, PA
Lease
Sales Office
Sales
Active
2,300 sqft
The Woodlands, TX
Lease
Engineering & Technology
N/A
Active
23,040 sqft
Dickinson, ND
Own
Field Operations
Hydraulic Fracturing
Active
21,772 sqft/34.9 acres
Shawnee, OK
Own
Field Operations
Hydraulic Fracturing
Active
39,100 sqft/56.1 acres
Mansfield, PA
Own
Field Operations
Hydraulic Fracturing, Wireline
Active
30,200 sqft/77.0 acres
Odessa, TX
Own
Field Operations
Hydraulic Fracturing, Wireline, Cementing
Active
97,006 sqft/40.0 acres
Springtown, TX
Own
Field Operations
Hydraulic Fracturing
Active
29,855 sqft/14.7 acres
Dickinson, ND
Lease
Field Operations
Hydraulic Fracturing
Active
33,375 sqft/9.7 acres
Williston, ND
Lease
Field Operations
Hydraulic Fracturing
Active
16,825 sqft/5.71 acres
Williston, ND
Lease
Field Operations
Hydraulic Fracturing, Wireline
Active
43,375 sqft
Mill Hall, PA
Lease
Field Operations
Hydraulic Fracturing, Wireline
Active
64,000 sqft/8.2 acres
New Stanton, PA
Lease
Field Operations
Hydraulic Fracturing, Wireline
Active
20,126 sqft/7.5 Acres
Pleasanton, TX
Lease
Field Operations
Hydraulic Fracturing
Active
10,488 acres
Alexander, ND
Lease
Field Maintenance and Storage Facility
Hydraulic Fracturing
Active
6,500 sqft/16.3 acres
Roanoke, TX
Lease
Warehouse
Hydraulic Fracturing, Wireline, Cementing
Active
49,500 sqft
Lewis Run, PA
Own
Abandoned
N/A
Idle
2,500 sqft
Mathis, TX
Own
Abandoned
Hydraulic Fracturing
Idle
66,725 sqft/47.4 acres
Oklahoma City, OK
Lease
Abandoned
Sales
Idle
3,366 sqft
Monessen, PA
Lease
Abandoned
Hydraulic Fracturing
Idle
78,220 sqft/7.9 Acres
Houston, TX
Lease
Abandoned
N/A
Idle
9,998 sqft


34




Item 3. Legal Proceedings
Legal Proceedings
Due to the nature of our business, we are, from time to time and in the ordinary course of business, involved in routine litigation or subject to disputes or claims related to our business activities. It is our management’s opinion that although the amount of liability with respect to certain of the matters described herein cannot be ascertained at this time, any resulting liability will not have a material adverse effect individually or in the aggregate on our financial condition, cash flows or results of operations; however, there can be no assurance as to the ultimate outcome of these matters.
On December 27, 2016, two former employees filed a complaint for a proposed collective action in United States District Court for the Southern District of Texas entitled Hickson and Villa v. Keane Group Holdings, LLC, et al., alleging certain field professionals were not properly classified under the Fair Labor Standards Act ("FLSA") and Pennsylvania law. The parties agreed to settle the claims in the first quarter of 2018 for $4.2 million. Settlement of this collective action is subject to court approval. Additionally, we are involved in a commercial dispute whereby a former customer has commenced an arbitration proceeding, captioned Halcon Operating Co., Inc. and Halcon Energy Properties, Inc. v. Keane Frac LP and Keane Frac GP, LLC, and on December 15, 2017, made a claim for contractual damages of approximately $4.0 million. The Company intends to vigorously dispute the merits of this asserted claim and plans to assert affirmative counterclaims for unpaid bills and other damages. Other than amounts previously accrued and disclosed, we are currently unable to estimate the range of loss, if any, that may result from these matters.

Item 4. Mine Safety Disclosures
Not applicable.

35




PART II
References Within This Annual Report
As used in Part II of this Annual Report on Form 10-K, unless the context otherwise requires, references to (i) the terms “Company,” “Keane,” “we,” “us” and “our” refer to Keane Group Holdings, LLC and its consolidated subsidiaries for periods prior to our initial public offering (“IPO”), and, for periods as of and following the IPO, Keane Group, Inc. and its consolidated subsidiaries; (ii) the term “Keane Group” refers to Keane Group Holdings, LLC and its consolidated subsidiaries; (iii) the term “Trican Parent” refers to Trican Well Service Ltd. and, where appropriate, its subsidiaries; (iv) the term “Trican U.S.” refers to Trican Well Service L.P.; (v) the term “Trican” refers to Trican Parent and Trican U.S., collectively; (vi) the term "RockPile" refers to RockPile Energy Services, LLC and its consolidated subsidiaries; (vii) the term "Keane Investor" refers to Keane Investor Holdings LLC and (viii) the terms “Sponsor” or “Cerberus” refer to Cerberus Capital Management, L.P. and its controlled affiliates and investment funds.
Item 5. Market for Registrant’s Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities
Market Information
On January 25, 2017, we consummated an initial public offering of our common stock at a price of $19.00 per share. Our common stock is traded on the New York Stock Exchange under the symbol “FRAC.” Prior to that time, there was no public market for our stock. As a result, we have not set forth quarterly information with respect to the high and low prices for our common stock for periods prior to January 20, 2017, the first day our common stock traded on the NYSE.
2017
 
 
High
 
Low
First Quarter (January 25, 2017 - March 31, 2017)
 
$
22.93

 
$
13.68

Second Quarter
 
$
16.81

 
$
12.42

Third Quarter
 
$
16.92

 
$
12.51

Fourth Quarter
 
$
19.13

 
$
13.63

 
 
 
 
 

36



Comparative Stock Performance Graph
The information contained in this Comparative Stock Performance Graph section shall not be deemed to be “soliciting material” or “filed” or incorporated by reference in future filings with the SEC, or subject to the liabilities of Section 18 of the Exchange Act, except to the extent that we specifically incorporate it by reference into a document filed under the Securities Act or the Exchange Act.
The graph below compares the cumulative total shareholder return on our common stock, the cumulative total return on the Standard & Poor's 500 Stock Index, the Standard & Poor's MidCap Index, the Oilfield Service Index and a composite average of publicly traded peer companies (C&J Energy Services, Inc., Patterson-UTI Energy, Inc., RPC, Inc., Superior Energy Services, Inc. and Weatherford International plc), since January 20, 2017, the first day our common stock traded on the NYSE.
The graph assumes $100 was invested on January 20, 2017, the first day our stock was traded on the NYSE, in our common stock, the Standard & Poor's 500 Stock Index, the Standard & Poor's MidCap Index, the Oilfield Service Index and a composite of publicly traded peer companies. The cumulative total return assumes the reinvestment of all dividends. We elected to include the stock performance of a composite of our publicly traded peers as we believe it is an appropriate benchmark for our line of business/industry.
compstockperform03.jpg
Holders
As of February 23, 2018, there were 10 shareholders of record of our common stock. The number of record holders does not include persons who held shares of our common stock in nominee or “street name” accounts through brokers.
Dividends
We do not currently intend to pay dividends. We are not required to pay dividends, and our stockholders will not be guaranteed, or have contractual or other rights to receive, dividends. The declaration and payment of any future dividends will be at the sole discretion of our board of directors and will depend upon, among other things, our earnings, financial condition, capital requirements, level of indebtedness, contractual restrictions with respect to the payment of dividends and other considerations that our board of directors deems relevant. Our board of directors

37



may decide, in its discretion, at any time, to modify or repeal the dividend policy or discontinue entirely the payment of dividends.
The ability of our board of directors to declare a dividend is also subject to limits imposed by Delaware corporate law. Under Delaware law, our board of directors and the boards of directors of our corporate subsidiaries incorporated in Delaware may declare dividends only to the extent of our “surplus,” which is defined as total assets at fair market value minus total liabilities, minus statutory capital, or if there is no surplus, out of net profits for the fiscal year in which the dividend is declared and/or the preceding fiscal year.
On February 26, 2018, we announced that our Board of Directors has authorized a stock repurchase program of up to $100 million of the Company’s outstanding common stock, with the intent of returning value to our shareholders as we continue to expect further growth and profitability. The duration of the stock buy-back program will be 12 months. The program does not obligate us to purchase any particular number of shares of common stock during any period, and the program may be modified or suspended at any time at our discretion.
Securities Authorized for Issuance Under Equity Compensation Plans
See Part II, "Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters" for information regarding securities authorized for issuance and Issuer Purchases of Equity Securities.
No shares of our common stock were repurchased during the three months ended December 31, 2017.

38




Item 6. Selected Financial Data
The selected financial data for periods was derived from the audited consolidated and combined financial statements of Keane and should be read in conjunction with Part I, “Item 1A. Risk Factors,” Part II, “Item 7. Management’s Discussion and Analysis of Financial and Results of Operations” and our audited consolidated and combined financial statements included in Part II, “Item 8. Financial Statements and Supplementary Data."
 
 
Year ended
December 31,
2017(1) 
 
Year ended December 31, 2016(2)
 
Year Ended
December 31,
2015
(in thousands of dollars, except per share amounts)
 
 
 
 
 
 
Statement of Operations Data:
 
 
 
 
 
 
Revenue
 
$
1,542,081

 
$
420,570

 
$
366,157

Cost of services(3)
 
1,282,561

 
416,342

 
306,596

Depreciation and amortization
 
159,280

 
100,979

 
69,547

Selling, general and administrative expenses
 
93,526

 
53,155

 
26,081

Gain on disposal of assets
 
(2,555
)
 
(387
)
 
(270
)
Impairment
 

 
185

 
3,914

Total operating costs and expenses
 
1,532,812

 
570,274

 
405,868

Operating income (loss)
 
9,269

 
(149,704
)
 
(39,711
)
Other expense (income), net
 
13,963

 
916

 
(1,481
)
Interest expense(4)
 
(59,223
)
 
(38,299
)
 
(23,450
)
Total other expenses
 
(45,260
)
 
(37,383
)
 
(24,931
)
Loss before income taxes
 
$
(35,991
)
 
$
(187,087
)
 
$
(64,642
)
Income tax expense
 
$
(150
)
 
$

 
$

Net loss
 
$
(36,141
)
 
$
(187,087
)
 
$
(64,642
)
Per Share Data(5)
 
 
 
 
 
 
Net loss per share - basic and diluted
 
$
(0.34
)
 
$
(2.14
)
 
$
(0.74
)
Weighted average number of shares - basic and diluted
 
106,321

 
87,313

 
87,313

Statement of Cash Flows Data:
 
 
 
 
 
 
Cash flows from operating activities
 
$
79,691

 
$
(54,054
)
 
$
37,521

Cash flows from investing activities
 
(250,776
)
 
(227,161
)
 
(26,038
)
Cash flows from financing activities
 
218,122

 
276,633

 
(10,518
)
Other Financial Data:
 
 
 
 
 
 
Capital expenditures(6)   
 
$
189,629

 
$
23,545

 
$
27,246

Adjusted EBITDA(8)    
 
214,525

 
1,921

 
41,885

Balance Sheet Data (at end of period):
 
 
 
 
 
 
Total assets
 
$
1,043,116

 
$
536,940

 
$
324,795

Long-term debt (including current portion) (7) 
 
275,055

 
269,750

 
207,067

Total liabilities
 
530,024

 
374,688

 
244,635

Total members’ equity
 
513,092

 
162,252

 
80,160

 
 
 
 
 
 
 

39



(1)
Commencing on July 3, 2017, our consolidated and combined financial statements also include the financial position, results of operations and cash flows of RockPile.
(2)
Commencing on March 16, 2016, our consolidated and combined financial statements also include the financial position, results of operations and cash flows of the Acquired Trican Operations (as defined herein).
(3)
Excludes depreciation and amortization, shown separately.
(4)
Interest expense during the year ended December 31, 2017 includes $15.8 million of prepayment penalties and $15.3 million in write-offs of deferred financing costs, incurred in connection with the refinancing by the Company (as defined herein) of its 2016 ABL Facility (as defined herein) and the Company's early debt extinguishment of its 2016 Term Loan Facility (as defined herein) and Senior Secured Notes (as defined herein).
(5)
The pro forma earnings per unit amounts have been computed to give effect to the Organizational Transactions, including the limited liability company agreement of Keane Investor to, among other things, exchange all of our Existing Owners’ membership interests for the newly-created ownership interests. The computations of earnings per unit do not consider the 15,700,000 shares of common stock newly-issued by the Company to investors in the IPO.
(6)
Capital expenditures do not include, for the year ended December 31, 2017, $116.6 million of capital expenditures related to the acquisition of RockPile and, for the year ended December 31, 2016, $205.4 million of capital expenditures related to the acquisition of the Acquired Trican Operations.
(7)
Long-term debt includes $8.1 million, $18.4 million and $8.9 million of unamortized debt discount and debt issuance costs for 2017, 2016 and 2015, respectively, and excludes capital lease obligations.
(8)
Adjusted EBITDA and Adjusted Gross Profit are Non-GAAP Measures that provide supplemental information we believe is useful to analysts and investors to evaluate our ongoing results of operations, when considered alongside other generally accepted accounting principles (“GAAP”) measures such as net income, operating income and gross profit. These non-GAAP financial measures exclude the financial impact of items we do not consider in assessing our ongoing operating performance, and thereby facilitate review of our operating performance on a period-to-period basis. Other companies may have different capital structures, and comparability to our results of operations may be impacted by the effects of acquisition accounting on its depreciation and amortization. As a result of the effects of these factors and factors specific to other companies, we believe Adjusted EBITDA and Adjusted Gross Profit provide helpful information to analysts and investors to facilitate a comparison of its operating performance to that of other companies.

Adjusted EBITDA is defined as net income (loss) adjusted to eliminate the impact of interest, income taxes, depreciation and amortization, along with certain items management does not consider in assessing ongoing performance. Adjusted Gross Profit is defined as Adjusted EBITDA, further adjusted to eliminate the impact of all activities in the Corporate segment, such as selling, general and administrative expenses, along with cost of services that management does not consider in assessing ongoing performance.    

40



Set forth below is a reconciliation of net loss to Adjusted EBITDA and Adjusted Gross Profit:
 
 
(Thousands of Dollars)

Year Ended December 31,
 
 
2017
 
2016
 
2015
 
Net loss
 
$
(36,141
)
 
$
(187,087
)
 
$
(64,642
)
 
Depreciation and amortization
 
159,280

 
100,979

 
69,547

 
Interest expense, net
 
59,223

 
38,299

 
23,450

 
Income tax (benefit) expense(a)
 
150

 
(114
)
 
793

 
EBITDA
 
$
182,512

 
$
(47,923
)
 
$
29,148

 
Acquisition, integration and expansion(b)
 
(4,674
)
 
35,630

 
6,272

 
Offering-related expenses(c)
 
7,069

 
1,672

 

 
Commissioning costs
 
12,565

 
9,998

 

 
Impairment of assets(d)
 

 
185

 
3,914

 
Non-cash stock compensation(e)
 
10,578

 
1,985

 
312

 
Other(f)
 
6,475

 
374

 
2,239

 
Adjusted EBITDA
 
$
214,525

 
$
1,921

 
$
41,885

 
Other income (expense)
 
(13,963
)
 
(916
)
 
$
1,481

 
Selling, general and administrative(a)
 
93,526

 
53,271

 
$
25,288

 
Management Adjustments not associated with Cost of Services
 
(19,128
)
 
(26,451
)
 
$
(7,740
)
 
Adjusted gross profit
 
$
274,960

 
$
27,825

 
$
60,914

 
 
 
 
 
 
 
 
 
(a)
Income tax (benefit) expense as presented in the consolidated and combined statement of operations does not include the provision for Texas margin tax for 2016 and the provisions for Texas margin tax and Canadian federal tax for 2015.
(b)
Represents professional fees, integration and divestiture costs, earn-outs, lease-termination costs, severance, start-up and other costs associated with the acquisition of RockPile and the Acquired Trican Operations, organic growth initiatives and wind-down of our Canadian operations. For the year ended December 31, 2017, $1.7 million was recorded in costs of services, $10.7 million was recorded in selling, general and administrative expense, $3.3 million gain was recorded in gain on disposal of assets and $13.8 million of income was recorded in other expense, net. For the year ended December 31, 2016, $13.9 million was recorded in costs of services, $23.2 million was recorded in selling, general and administrative expenses and $0.3 million was recorded in other expense, net. For the year ended December 31, 2015, $1.1 million was recorded in costs of services, $3.5 million was recorded in selling, general and administrative expenses and $1.7 million was recorded in other expense, net.
(c)
Represents professional fees and other miscellaneous expenses related to the Organizational Transactions (defined herein), the Company's initial public offering and the sale of the Company's stock by a selling stockholder in January 2018. For the year ended December 31, 2017, $1.3 million was recorded in cost of services and $5.8 million was recorded in selling, general and administrative expense. For the year ended December 31, 2016, $1.7 million was recorded in selling, general and administrative expenses.
(d)
Represents non-cash impairment charges with respect to our long-lived assets and intangible assets.
(e)
In 2017, represents non-cash amortization of equity awards issued under Keane Group, Inc.’s Equity and Incentive Award Plan (the "Plan"). According to the Plan, the Compensation Committee of the Board of Directors can approve awards in the form of restricted stock, restricted stock units, and/or other deferred compensation. In 2016 and 2015, represents adjustments to the non-cash profit interests related to Keane Group Holdings, LLC. In all three years, these costs were recorded in selling, general and administrative expenses.
(f)
Represents contingency accruals related to certain litigation claims, readiness costs associated with Keane's initial internal controls design documentation for Sarbanes-Oxley compliance, using COSO 2013 framework, net gains on disposal of assets, forfeiture of deposit on hydraulic fracturing equipment purchase orders and other miscellaneous charges. For the year ended December 31, 2017, $0.8 million was recorded in gain on disposal of assets and $5.8 million was recorded in selling, general and administrative expenses. For the year ended December 31, 2016, $0.4 million was recorded in other expense, net. For the year ended December 31, 2015, $0.2 million was recorded in costs of services and $2.0 million was recorded in other expense, net.

41



Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our financial statements and related notes included within Part II, “Item 8. Financial Statements and Supplementary Data” in this Annual Report on Form 10-K.
On January 25, 2017, we consummated an IPO of 30,774,000 shares of our common stock, of which 15,700,000 shares were offered by us and 15,074,000 shares were offered by the selling stockholder. To effectuate the IPO, we effected a series of transactions that resulted in a reorganization of our business. Specifically, among other transactions, we effected the Organizational Transactions described within Note (1) Basis of Presentation and Nature of Operations of Part II, “Item 8. Financial Statements and Supplemental Data.”
The information in this “Management’s Discussion of Analysis of Financial Condition and Results of Operations” reflects the following: (1) as it pertains to periods prior to the completion of the IPO, the accounts of Keane Group; and (2) as it pertains to the periods subsequent to the completion of the IPO, the accounts of Keane.
This section and other parts of this Annual Report on Form 10-K contain forward-looking statements, within the meaning of the Private Securities Litigation Reform Act of 1995, which are subject to risks and uncertainties. Forward-looking statements provide current expectations of future events based on certain assumptions and include any statement that does not directly relate to any historical or current fact. Forward-looking statements can also be identified by words such as “aim,” “anticipate,” “believe,” “estimate,” “expect,” “forecast,” “future,” “intend,” “outlook,” “plan,” “potential,” “predict,” “project,” “seek,” “may,” “can,” “will,” “would,” “could,” “should,” the negatives thereof and other similar expressions. Forward-looking statements are not guarantees of future performance and actual results may differ significantly from the results discussed in the forward-looking statements. Factors that might cause such differences include, but are not limited to, those discussed in Part I, “Item 1A. Risk Factors” of this Annual Report on Form 10-K under the heading “Risk Factors,” which are incorporated herein by reference. The following discussion should be read in conjunction with the consolidated financial statements and notes thereto included in Part II, “Item 8. Financial Statements and Supplementary Data” of this Annual Report on Form 10-K. All information presented herein is based on our fiscal calendar. Unless otherwise stated, references to particular years, quarters, months or periods refer to our fiscal years and the associated quarters, months and periods of those fiscal years. We undertake no obligation to revise or update any forward-looking statements for any reason, except as required by law.
EXECUTIVE OVERVIEW
Organization
We are one of the largest pure-play providers of integrated well completion services in the U.S., with a focus on complex, technically demanding completion solutions. Our primary service offerings include horizontal and vertical fracturing, wireline perforation and logging and engineered solutions, as well as other value-added service offerings. Our total capacity includes approximately 1.2 million hydraulic horsepower. From our 26 currently deployable hydraulic fracturing fleets (“fleets”), 31 wireline trucks, 24 cementing pumps and other ancillary assets located in the Permian Basin, the Marcellus Shale/Utica Shale, the Eagle Ford Formation, the Bakken Formation and other active oil and gas basins, we pride ourselves on providing industry-leading completion services with a strict focus on health, safety and environmental stewardship and cost-effective customer-centric solutions. We distinguish ourselves through our partnerships with our customers, our transparency concerning value creation and our responsibilities to employees and customers.
In December 2017, we placed orders for an aggregate of approximately 150,000 newbuild hydraulic horsepower representing three additional hydraulic fracturing fleets, with anticipated capital expenditures for the three fleets of approximately $115.0 million, expected to be delivered in the second and third quarters of 2018.

42


We provide our services in conjunction with onshore well development, in addition to stimulation operations on existing wells, to well-capitalized oil and gas exploration and production customers, with some of the highest quality and safety standards in the industry and long-term development programs that enable us to maximize operational efficiencies and the return on our assets. We believe our integrated approach and proven capabilities enable us to deliver cost-effective solutions for increasingly complex and technically demanding well completion requirements, which include longer lateral segments, higher pressure rates and proppant intensity, and multiple fracturing stages in challenging high-pressure formations. In addition, our technical team and engineering center, which is located in The Woodlands, Texas, provides us the ability to supplement our service offerings with engineered solutions specifically tailored to address customers’ completion requirements and unique challenges.
We are organized into two reportable segments, consisting of Completion Services, which includes our hydraulic fracturing and wireline divisions and ancillary services; and Other Services, which includes our cementing and drilling divisions. We evaluate the performance of these segments based on equipment utilization, revenue, segment gross profit and gross margin. Segment gross profit is a key metric that we use to evaluate segment operating performance and to determine resource allocation between segments. We define segment gross profit as segment revenue less segment direct and indirect cost of services, excluding depreciation and amortization. Additionally, our operations management make rapid and informed decisions, including price adjustments to offset commodity inflation and align with market, decisions to strategically deploy our existing and new fleets and real-time supply chain management decisions, by utilizing top line revenue, as well as individual direct and indirect costs on a per stage and per fleet basis.
Acquisition of RockPile
On July 3, 2017, the Company acquired 100% of the outstanding equity interests of RockPile. RockPile was a multi-basin provider of integrated well completion services in the United States, whose primary service offerings included hydraulic fracturing, wireline perforation and workover rigs. The acquisition of RockPile was completed for cash consideration of $116.6 million, subject to post-closing adjustments, 8,684,210 shares of the Company’s common stock and contingent value rights (“CVR”) granted pursuant to the CVR Agreement, as further described in Note (3) Acquisitions) of Part II, “Item 8. Financial Statements and Supplementary Data” of this Annual Report on Form 10-K and in the Company's Current Report on Form 8-K filed on July 3, 2017.
Through this acquisition, we expanded our existing presence in the Permian Basin and Bakken Formation by increasing our pumping capacity by more than 25%, further strengthening our position as one of the largest pure-play providers of integrated well completion services in the United States. We acquired 245,000 hydraulic horsepower at newbuild economics, eight wireline trucks, 10 cementing units and 12 workover rigs. We also acquired a high-quality customer base, with minimal overlap to our existing customer base and expanded certain service offerings and capabilities within our Other Services segment.
Subsequent to the acquisition, we sold the twelve acquired workover rigs during the third and fourth quarters of 2017.
Financial results
Revenue in 2017 totaled $1.5 billion, an increase of 267% compared to revenue in 2016 of $420.6 million. Our strong revenue growth in 2017 was driven by the following factors, (i) completion of the acquisition of RockPile, which added 245,000 hydraulic horsepower, the largest contributor to year over year growth, (ii) continued deployment of available horsepower with seven fleets commissioned and deployed in 2017 and (iii) continued execution of our pricing strategy of aligning pricing with our clients under dedicated agreements with periodic re-openers priced at market rate. We exited 2016 with 13 operating fleets and exited 2017 with 26 operating, with six fleets, including one newbuild fleet, acquired through the acquisition of RockPile. On an average basis, we operated 21.1 fleets during 2017 compared to 9.8 fleets during 2016. The revenue growth drivers for 2017 had a favorable impact on operating margins, which is calculated by dividing operating income (loss) by revenue, but headwinds in input cost inflation persisted, particularly with sand, trucking, labor, and chemicals. Consistent

43


with our efforts to maintain and grow the supply of key commodities and skilled workforce, as influenced by market capacity, we continued to secure key contracts with suppliers, as well as position labor rates to facilitate retaining skilled employees and attracting new talent. We reported operating income of $9.3 million in 2017, as compared to an operating loss of $149.7 million in 2016.
We reported net loss of $36.1 million, or $0.34 per basic and diluted share, in 2017, compared to net loss of $187.1 million, or $2.14 per basic and diluted share, in 2016. Net income in 2017 includes $15.4 million of management adjustments to cost of services to arrive at Adjusted Gross Profit. Approximately $12.4 million of this amount was driven by costs for the re-commissioning of seven previously idled fleet, $1.7 million by acquisition and integration costs incurred for the acquisition of RockPile and $1.3 million by bonuses paid out to key operational employees in connection with our IPO. Approximately $34.5 million of management adjustments to selling, general and administrative expenses to arrive at Adjusted EBITDA during 2017 were driven by $10.7 million of transaction costs primarily incurred for the acquisition of RockPile, $10.6 million of non-cash compensation expense for the restricted stock units and stock options awarded to certain of our employees in connection with our IPO, $5.8 million of organizational restructuring costs and bonuses to key personnel in connection with our IPO, as well as transaction costs related to our secondary offering in 2018, $7.2 million primarily related to litigation contingencies and $0.2 million in commissioning costs. Approximately $4.1 million of management adjustments to (gain) loss on disposal of assets to arrive at Adjusted EBITDA during 2017 were related to the sale of our coiled tubing units and ancillary coiled tubing equipment, our air compressor units and idle property in Woodward, Oklahoma and Searcy, Arkansas. See Note (7) Property and Equipment, net of Part II,"Item 8. Financial Statements and Supplementary Data" for further details on these asset sales. Approximately $13.8 million of management adjustments to other income to arrive at Adjusted EBITDA during 2017 was primarily driven by $7.8 million of gain on indemnification settlements with Trican, $0.7 million due to the negotiated settlement of assumed liabilities with a certain vendor from a prior acquisition and a $5.3 million mark-to-market valuation adjustment of the CVR associated with the acquisition of RockPile.
Business outlook
Commodity prices improved significantly throughout 2017, following a period of depressed prices and activity throughout the industry downturn of 2015 and 2016. West Texas Intermediate (“WTI”) crude oil prices averaged $50.88 per barrel in 2017, compared to a low of $26.19 per barrel in February 2016. Henry Hub Natural Gas prices averaged $2.99 per MMBtu in 2017, compared to a low of $1.49 per MMBtu in March 2016. The general rebound in commodity prices has led to an increase in drilling activity across the industry, with total U.S. land rig count averaging 856 rigs in 2017, compared to an average of 486 rigs in 2016.
The increase in drilling rigs and activity, combined with the completion of previously drilled wells, has led to a significant growth in the demand for U.S. completions services. We continue to expect improvements in demand and higher leading-edge pricing for our services across our diversified footprint, as the availability of high-quality hydraulic fracturing equipment remains tight, capital expenditure for drilling and completions in the U.S. stabilizes at a higher level of activity and customers place increased focus on partnering with well-capitalized, safe and efficient service providers.
Given the energy industry's outlook for 2018 activity levels, we expect further increases in the demand for our services over the next several quarters, driven by supportive industry fundamentals, including higher commodity prices and increases in completions intensity. Across the industry, exploration and production companies are executing completion designs with greater intensity, including longer laterals, more stages per well, tighter well spacing and increased proppant loadings. We believe the availability and supply of completions services is impacted by increases in completions intensity, resulting in increases in the amount of equipment that must be utilized per job and acceleration of maintenance cycles, both of which have a tightening effect on available supply. Furthermore, given the fragmented nature of the completions services industry, combined with varying levels of asset readiness and capital availability, we expect further consolidation in the industry.

44


Oil and natural gas prices are significant drivers behind the pace and location of our customer activity. We actively monitor the trends in oil and natural gas prices and focus on maintaining flexibility. While commodity prices have improved throughout 2017 and into 2018, we expect volatility and uncertainty to remain in place throughout the year. This backdrop, combined with asset attrition and newbuild lead-times, should support an environment for attractive cash generation on our fleets throughout 2018.
The industry continues to face strain in sand supply, driven by weather-induced rail congestion, combined with mine-related issues due to rail-related output constraints, flooding impacts, delays on local mine start-ups and continued growth in demand. We are proactively managing these transitory issues facing the entire industry to limit the impact to our customers and business. In addition, continued tightening of the labor market could result in higher wage rates, as well as increased recruiting, hiring, onboarding and training costs.
We continue to believe in the strength of the near-term and long-term fundamentals of our business, including our high-quality, fit-for-purpose and well-maintained equipment, our financial strength and discipline and the scale and flexibility of our supply chain.
Fiscal 2017 Highlights
IPO: completed initial public offering and listing of common stock on NYSE
Utilization: deployed all idle fleets at attractive cost with full utilization
Newbuild: placed preemptive and strategic order for three newbuild fleets
Profitability: continued to increase annualized Adjusted Gross Profit per fleet
Mergers and acquisition: executed strategic acquisition of RockPile
Balance sheet: maintained and improved conservative balance sheet and liquidity
Portfolio optimization: sold workover rigs acquired in the acquisition of RockPile and coiled tubing assets acquired in the acquisition of the Acquired Trican Operations
Fiscal 2018 Outlook
In 2018, our principal business objective continues to be growing our business and safely providing best-in-class services in other Completion Services and Other Services segments. We expect to achieve our objective through:
partner and grow with customers who focus their efforts on high-efficiency completions jobs under dedicated agreements;
allocate our assets to maximize utilization and returns, including diversification of geography and commodity;
improve profitability of fully-utilized fleets through increased leading-edge pricing and efficiencies;
leverage our flexible and scalable logistics infrastructure to provide assurance of timely supply at lowest landed cost;
leverage our platform to identify, retain and promote talent to sustain growth and support operational excellence;
pursue expansion opportunities for our cementing assets;

45


maintain agreements with our existing strategic suppliers and identify and develop relationships with additional strategic suppliers to ensure continuity of supply;
maintain our conservative and flexible capital position, supporting continued growth and maintenance of active equipment; and
explore potential opportunities for mergers or acquisitions, focused on portfolio expansion and market opportunities.
Our operating performance and business outlook are described in more detail in “Business Environment and Results of Operations” herein.
Financial markets, liquidity, and capital resources
On January 25, 2017, the Company completed the IPO of 30,774,000 shares of its common stock at the public offering price of $19.00 per share, which included 15,700,000 shares offered by the Company and 15,074,000 shares offered by the selling stockholder, including 4,014,000 shares sold as a result of the underwriters’ exercise of their overallotment option. The IPO proceeds to the Company, net of underwriters’ fees and capitalized cash payments of $4.8 million for professional services and other direct IPO related activities, was $255.5 million. The net proceeds were used to fully repay KGH Intermediate Holdco II, LLC (“Holdco II”)’s 2016 Term Loan Facility balance of $99.0 million and the associated prepayment premium of $13.8 million, and to repay $50.0 million of its 12% secured notes due 2019 (“Senior Secured Notes”) and the associated prepayment premium of approximately $0.5 million. The remaining proceeds were used for general corporate purposes, including capital expenditures, working capital and potential acquisitions and strategic transactions. Upon completion of the IPO and the reorganization, the Company had 103,128,019 shares of common stock outstanding.
On February 17, 2017, we also obtained a $150.0 million asset-based revolving credit facility ("2017 ABL Facility"), replacing our pre-existing $100.0 million asset-based revolving credit facility. On December 22, 2017, our 2017 ABL Facility was amended to increase the commitments thereunder by $150.0 million, for total commitments of $300.0 million.
On March 15, 2017, we obtained a $150.0 million term loan facility (the “2017 Term Loan Facility”). We used the proceeds from our 2017 Term Loan Facility to fully repay our Senior Secured Notes. On July 3, 2017, we secured $135.0 million in incremental term loans under an incremental term loan facility (the “Incremental Term Loan Facility” and together with the 2017 Term Loan Facility, the “New Term Loan Facility”), which are subject to substantially the same terms as the outstanding initial term loans under the 2017 Term Loan Facility. The majority of the proceeds from the incremental term loans was used to fund our acquisition of 100% of the outstanding equity interests of RockPile. As a result of entering into the Incremental Term Loan Facility, we expect our average annualized interest expense to increase from $12.4 million to $23.6 million.
At December 31, 2017, we had approximately $96.1 million of cash available. We also had $199.7 million available under our asset-based revolving credit facility as of December 31, 2017, which, with our cash balance, we believe provides us with sufficient liquidity for at least the next 12 months, including for capital expenditures and working capital investments.
On January 17, 2018, our Registration Statement on Form S-1 (File No. 333-222500) was declared effective by the SEC for an offering of shares of our common stock on behalf of Keane Investor (the "selling stockholder"), pursuant to which 15,320,015 were registered and sold by the selling stockholder (including 1,998,262 shares sold pursuant to the exercise of the underwriters' over-allotment option), at a price to the public of $18.25 per share. We did not sell any common stock in, and did not receive any of the proceeds from, the secondary offering. Following completion of the secondary offering, Keane Investor owns approximately 50.7% of the Company's outstanding common stock. We incurred $1.2 million of transaction costs related to the secondary offering in 2017, which were included under selling, general and administrative expenses within the consolidated

46


and combined statement of operations. We anticipate we will incur approximately $12.9 million of transactions costs related to the secondary offering in 2018, primarily related to the payment of underwriting discounts and commissions payable by the Company.
For additional information on market conditions and our liquidity and capital resources, see “Liquidity and Capital Resources,” and “Business Environment and Results of Operations” herein.
BUSINESS ENVIRONMENT AND RESULTS OF OPERATIONS
We provide our services in several of the most active basins in the U.S., including the Permian Basin, the Marcellus Shale/Utica Shale, the Eagle Ford Formation and the Bakken Formation. These regions are expected to account for approximately 70% of all new horizontal wells anticipated to be drilled during 2018 and 2019. In addition, the high density of our operations in the basins in which we are most active provides us the opportunity to leverage our fixed costs and to quickly respond with what we believe are highly efficient, integrated solutions that are best suited to address customer requirements.
In particular, we are one of the largest providers in the Permian Basin, Eagle Ford Basin and the Marcellus Shale/Utica Shale, the most prolific and cost-competitive oil and natural gas basins in the United States. According to Spears & Associates, the Permian Basin, Eagle Ford Basin and the Marcellus Shale/Utica Shale are expected to account for 61% of total active rigs in the U.S. during 2018 through 2022 based on forecasted rig counts. These basins have experienced a recovery in activity since the spring of 2016, with an 166% increase in rig count from their combined May 2016 low of 194 to 516 as of December 31, 2017.
Activity within our business segments is significantly impacted by spending on upstream exploration, development, and production programs by our customers. Also impacting our activity is the status of the global economy, which impacts oil and natural gas consumption.
Some of the more significant determinants of current and future spending levels of our customers are oil and natural gas prices, global oil supply, the world economy, the availability of credit, government regulation and global stability, which together drive worldwide drilling activity. Our financial performance is significantly affected by rig and well count in North America, as well as oil and natural gas prices, which are summarized in the tables below.
The following table shows the average oil and natural gas prices for WTI and Henry Hub natural gas:
 
 
Year Ended December 31,
 
 
2017
 
2016
 
2015
Oil price - WTI(1)
 
$
50.88

 
$
43.14

 
$
48.69

Natural gas price - Henry Hub(2)
 
2.99

 
2.52

 
2.63

(1)  Oil price measured in dollars per barrel
(2)  Natural gas price measured in dollars per million British thermal units (Btu), or MMBtu
 
 
 
 
 
 
 

47



The historical average U.S. rig counts based on the weekly Baker Hughes Incorporated rig count information were as follows:
 
 
Year Ended December 31,
Product Type
 
2017
 
2016
 
2015
Oil
 
703

 
408

 
750

Natural Gas
 
172

 
100

 
227

Other
 
1

 
1

 
1

Total
 
876

 
509

 
978

 
 
 
 
 
 
 
 
 
Year Ended December 31,
Drilling Type
 
2017
 
2016
 
2015
Horizontal
 
736

 
400

 
744

Vertical
 
70

 
60

 
139

Directional
 
70

 
49

 
95

Total
 
876

 
509

 
978

 
 
 
 
 
 
 
Our customers’ cash flows, in most instances, depend upon the revenue they generate from the sale of oil and natural gas. Lower oil and natural gas prices usually translate into lower exploration and production budgets.
Following a trough in early 2016, oil prices and natural gas prices have recovered to $60.46 and $3.69, respectively, or approximately 131% and 148%, respectively, as of December 29, 2017, from their lows in early 2016 of $26.19 and $1.49, respectively. The US Energy Information Administration (the “EIA”) projects WTI spot prices to average $56.0 and $57.0 and Henry Hub natural gas prices to average $2.88 and $2.92 in 2018 and 2019, respectively.
With the rebound in commodity prices from their lows in early 2016, drilling and completion activity has continued to increase in 2017, with U.S. active rig count in December 2017 more than doubling the trough in the active rig count registered in May 2016. The significant growth in production resulting from increased drilling activity has contributed to increased uncertainty concerning the direction of oil and gas prices over the near and immediate term, and market volatility has continued to persist. Despite this market volatility, we continue to experience increased demand for our services and believe we are in a more stable demand environment than existed during the above-mentioned market decline.
The EIA projects that the average WTI spot price will increase through 2040 from growing demand and the development of more costly oil resources. Global liquids demand is expected to increase by approximately 1.0 million barrels per day from 2017 to 2018. The EIA anticipates continued growth in the long-term U.S. domestic demand for natural gas, supported by various factors, including (i) expectations of continued growth in the U.S. gross domestic product; (ii) an increased likelihood that regulatory and legislative initiatives regarding domestic carbon emissions policy will drive greater demand for cleaner burning fuels such as natural gas; (iii) increased acceptance of natural gas as a clean and abundant domestic fuel source that can lead to greater energy independence of the U.S. by reducing its dependence on imported petroleum; (iv) the emergence of low-cost natural gas shale developments; and (v) continued growth in electricity generation from intermittent renewable energy sources, primarily wind and solar energy, for which natural-gas-fired generation is a logical back-up power supply source. Natural gas demand in North America is expected to increase by approximately 6.9 billion cubic feet per day from 2017 to 2018.
Across the industry, customers are executing well designs with increased sand tonnage pumped to help supersize their wells to increase well productivity. This increase in sand tonnage pumped has led to a significant

48



tightening in the market for sand and sand transportation. Coras Research, LLC forecasts that average proppant pumped per horizontal well will increase 18% to 14.4 million pounds by 2019 from an estimated 12.2 million pounds in 2017.

49



RESULTS OF OPERATIONS IN 2017 COMPARED TO 2016
Year Ended December 31, 2017 Compared with Year Ended December 31, 2016
 
 
Year Ended December 31,
(Thousands of Dollars)
 
 
 
 
 
As a % of Revenue
 
Variance 
Description
 
2017
 
2016
 
2017
 
2016
 
$
 
%
Completion Services
 
$
1,527,287

 
$
410,854

 
99
%
 
98
%
 
$
1,116,433

 
272
%
Other Services
 
14,794

 
9,716

 
1
%
 
2
%
 
5,078

 
52
%
Revenue
 
1,542,081

 
420,570

 
100
%
 
100
%
 
1,121,511

 
267
%
Completion Services
 
1,269,263

 
401,891

 
82
%
 
96
%
 
867,372

 
216
%
Other Services
 
13,298

 
14,451

 
1
%
 
3
%
 
(1,153
)
 
(8
%)
Costs of services (excluding depreciation and amortization, shown separately)
 
1,282,561

 
416,342

 
83
%
 
99
%
 
866,219

 
208
%
Completion Services
 
258,024

 
8,963

 
17
%
 
2
%
 
249,061

 
2,779
%
Other Services
 
1,496

 
(4,735
)
 
0
%
 
(1
%)
 
6,231

 
(132
%)
Gross profit
 
259,520

 
4,228

 
17
%
 
1
%
 
255,292

 
6,038
%
Depreciation and amortization
 
159,280

 
100,979

 
10
%
 
24
%
 
58,301

 
58
%
Selling, general and administrative expenses
 
93,526

 
53,155

 
6
%
 
13
%
 
40,371

 
76
%
(Gain) on disposal of assets
 
(2,555
)
 
(387
)
 
0
%
 
0
%
 
(2,168
)
 
560
%
Impairment
 

 
185

 
0
%
 
0
%
 
(185
)
 
(100
%)
Operating income (loss)
 
9,269

 
(149,704
)
 
1
%
 
(36
%)
 
158,973

 
(106
%)
Other income, net
 
13,963

 
916

 
1
%
 
0
%
 
13,047

 
1,424
%
Interest expense
 
(59,223
)
 
(38,299
)
 
(4
%)
 
(9
%)
 
(20,924
)
 
55
%
Total other expenses
 
(45,260
)
 
(37,383
)
 
(3
%)
 
(9
%)
 
(7,877
)
 
21
%
Income tax expense
 
(150
)
 

 
0
%
 
0
%
 
(150
)
 
0
%
Net income (loss)
 
$
(36,141
)
 
$
(187,087
)
 
(2
%)
 
(44
%)
 
$
150,946

 
(81
%)
 
 
 
 
 
 
 
 
 
 
 
 
 
Revenue.     Total revenue is comprised of revenue from Completion Services and Other Services. Revenue in 2017 increased by $1.1 billion, or 267%, to $1.5 billion from $420.6 million in 2016. This change in revenue by reportable segment is discussed below.
Completion Services:     Completion Services segment revenue increased by $1.1 billion, or 272%, to $1.5 billion in 2017 from $410.9 million in 2016. This change was primarily attributable to a 105% growth in our average number of deployed fleets, as a result of increased utilization of our combined asset base following our acquisition of RockPile and our acquisition of the majority of the U.S. assets and assumptions of certain liabilities of Trican Well Service, L.P. (the “Acquired Trican Operations”), as well as increased stage count and efficiency from both our existing and newly-deployed recommissioned fleets. In addition, annualized revenue per deployed fleet increased 81%.
Other Services:     Other Services segment revenue increased by $5.1 million, or 52%, to $14.8 million in 2017 from $9.7 million in 2016. This change in revenue was primarily attributable to the acquisition of Other Services divisions from RockPile. Revenue in 2017 was earned in our cementing and workover divisions and revenue in 2016 was earned in our cementing and coiled tubing divisions. We idled our coiled tubing division in

50



December 2016 and divested of our coiled tubing assets during the fourth quarter of 2017. We divested of our workover assets during the third and fourth quarters of 2017.
Cost of services.     Cost of services in 2017 increased by $866.2 million, or 208%, to $1.3 billion from $416.3 million in 2016. This change was driven by several factors including (i) higher activity in the Completion Services segment (as discussed above under Revenue), (ii) price inflation in our key input costs, including labor, sand and sand trucking, (iii) increased maintenance costs associated with increased service intensity stemming from larger sand volumes and well configurations, such as zipper designs, (iv) an increase in fleets working twenty-four hour operations and (v) rapid deployment and commissioning of our idle fleets. In 2017, we incurred $12.4 million of fleet commissioning costs, $1.7 million of acquisition and integration costs associated with the acquisition of RockPile and $1.3 million for bonuses paid out to key operational employees in connection with our IPO. In 2016, we had management adjustments of $13.9 million primarily related to acquisition and integration costs associated with the acquisition of the Acquired Trican Operations and $10.0 million primarily related to commissioning of our idle fleets. Cost of services as a percentage of total revenue in 2017 was 83%, which represented a decrease of 16% from 99% in 2016. Excluding the above-mentioned management adjustments, total cost of services was $1.27 billion and $392.4 million in 2017 and 2016 or 82% and 93% of revenue, respectively, a decrease as a percentage of revenue of 11%.
Cost of services, as a percentage of total revenue is presented below:
 
 
Year Ended December 31,
Description
 
2017
 
2016
 
% Change
Segment cost of services as a percentage of segment revenue:
 
 
 
 
 
 
Completion Services
 
83
%
 
98
%
 
(15
)%
Other Services
 
90
%
 
149
%
 
(59
)%
Total cost of services as a percentage of total revenue
 
83
%
 
99
%
 
(16
)%
 
 
 
 
 
 
 
The change in cost of services by reportable segment is further discussed below.
Completion Services:     Completion Services segment cost of services increased by $867.4 million, or 216%, to $1.3 billion in 2017 from $401.9 million in 2016. As a percentage of segment revenue, total cost of services was 83% and 98%, in 2017 and 2016, respectively, a decrease as a percentage of revenue of 15%. This change in cost of services was driven by (i) higher activity (as discussed above under Revenue), (ii) price inflation in our key input costs, including sand and trucking, (iii) increased maintenance costs associated with increased service intensity and higher-pressure jobs and (iv) rapid deployment and commissioning of our idle fleets. In 2017, we incurred $11.6 million of fleet commissioning costs, $1.7 million of acquisition and integration costs associated with the acquisition of RockPile and $1.3 million for bonuses paid out to key operational employees in connection with our IPO. In 2016, we had management adjustments of $13.5 million primarily related to acquisition and integration costs associated with the acquisition of the Acquired Trican Operations and $9.3 million primarily related to commissioning of our idle fleets. Excluding the above-mentioned management adjustments, Completion Services segment cost of services were $1.25 billion and $379.1 million in 2017 and 2016, or 82% and 92% of segment revenue, respectively, a decrease as a percentage of revenue of 10%.
Other Services:     Other Services segment cost of services decreased by $1.2 million, or 8%, to $13.3 million in 2017 from $14.5 million in 2016. This change in cost of services was primarily attributable to the idling of our cementing and coiled tubing divisions in April 2016 and December 2016, respectively, partially offset by the acquisition of Other Services divisions from RockPile. In 2017, we incurred management adjustments of $0.8 million of commissioning costs related to ramping our idle cementing assets in response to increased customer demand and $0.05 million of acquisition and integration costs associated with the acquisition of RockPile. In 2016, we incurred management adjustments of $0.7 million in commissioning costs and $0.4 million in acquisition and integration costs associated with the Acquired Trican Operations. Excluding the above-mentioned management

51



adjustments, Other Services segment cost of services was $12.4 million and $13.4 million in 2017 and 2016, or 84% and 138% of segment revenue, respectively, a decrease as a percentage of revenue of 54%.
Depreciation and amortization.     Depreciation and amortization expense increased by $58.3 million, or 58%, to $159.3 million in 2017 from $101.0 million in 2016. This change was primarily attributable to depreciation of additional equipment purchased in 2017 to recondition existing fleets and the acquisition of the RockPile assets.
Selling, general and administrative expense.     Selling, general and administrative (“SG&A”) expense, which represents costs associated with managing and supporting our operations, increased by $40.4 million, or 76%, to $93.5 million in 2017 from $53.2 million in 2016. This change in SG&A was primarily related to non-cash amortization expense of equity awards issued under our Equity and Incentive Award Plan in 2017 and transactions driving overall company growth associated with the acquisition of RockPile. SG&A as a percentage of total revenue was 6% in 2017 compared with 13% in 2016. Total management adjustments were $34.5 million in 2017, driven by $10.7 million of transaction costs primarily incurred for the acquisition of RockPile, $10.6 million of non-cash compensation expense for the restricted stock units and stock options awarded to certain of our employees in connection with our IPO, $5.8 million of organizational restructuring costs and bonuses to key personnel in connection with our IPO, as well as transaction costs related to our secondary offering in 2018, $7.2 million primarily related to litigation contingencies and $0.2 million related to acquisition and integration costs associated with the acquisition of RockPile. Management adjustments in 2016 were $26.9 million, primarily driven by $23.2 million of transaction costs and lease exit costs related to the integration of the Acquired Trican Operations, $2.0 million in non-cash compensation expense of our unit-based awards and $1.7 million in IPO-readiness costs. Excluding these management adjustments, SG&A expense was $59.0 million and $26.3 million in 2017 and 2016, respectively, which represents an increase of 124%.
Gain on disposal of assets.     Gain on disposal of assets in 2017 increased by $2.2 million, or 560%, to a gain of $2.6 million in 2017 from a gain of $0.4 million in 2016. This change was primarily attributable to the sale of our coiled tubing units and ancillary coiled tubing equipment, our air compressor units and idle property in Woodward, Oklahoma and Searcy, Arkansas.
 Other income (expense), net.     Other income (expense), net, in 2017 increased by $13.0 million, or 1,424%, to income of $14.0 million in 2017 from income of $0.9 million in 2016. This change is primarily due to $7.8 million of gain on indemnification settlements with Trican, $0.7 million due to the negotiated settlement of assumed liabilities with a certain vendor from a prior acquisition and a $5.3 million mark-to-market valuation adjustment of the contingent value rights granted by the Company in connection with the acquisition of RockPile.
 Interest expense, net.     Interest expense, net of interest income, increased by $20.9 million, or 55%, to $59.2 million in 2017 from $38.3 million in 2016. This change was primarily attributable to prepayment premiums of $15.8 million and write-offs of deferred financing costs of $15.3 million, incurred in connection with the refinancing of our asset-based revolving credit facility and debt extinguishment of our 2016 Term Loan Facility and Senior Secured Notes. This increase was offset by lower interest expense under our New Term Loan Facility, which replaced our 2016 Term Loan Facility and Senior Secured Notes that bore higher interest rates.
Effective tax rate.     Upon consummation of the IPO, the Company became a corporation subject to federal income taxes. Our effective tax rate on continuing operations in 2017 was (0.53)%. The effective rate is primarily made up of a tax benefit derived from the current period operating income offset by a valuation allowance. As a result of market conditions and their corresponding impact on our business outlook, we determined that a valuation allowance was appropriate as it is not more likely than not that we will utilize our net deferred tax assets. The remaining tax impact not offset by a valuation allowance is related to tax amortization on our indefinite-lived intangible assets.
Net loss.     Net loss was $36.1 million in 2017, as compared with net loss of $187.1 million in 2016. The decrease from the net loss in 2016 is due to the changes in revenue and expenses discussed above.

52



Year Ended December 31, 2016 Compared with Year Ended December 31, 2015
 
 
Year Ended December 31,
(Thousands of Dollars)
 
 
 
 
 
As a % of Revenue
 
Variance 
Description
 
2016
 
2015
 
2016
 
2015
 
$
 
%
Completion Services
 
$
410,854

 
$
363,820

 
98
%
 
99
%
 
$
47,034

 
13
%
Other Services
 
9,716

 
2,337

 
2
%
 
1
%
 
7,379

 
316
%
Revenue
 
420,570

 
366,157

 
100
%
 
100
%
 
54,413

 
15
%
Completion Services
 
401,891

 
305,036

 
96
%
 
83
%
 
96,855

 
32
%
Other Services
 
14,451

 
1,560

 
3
%
 
0
%
 
12,891

 
826
%
Cost of services (excluding depreciation and amortization, shown separately)
 
416,342

 
306,596

 
99
%
 
84
%
 
109,746

 
36
%
Completion Services
 
8,963

 
58,784

 
2
%
 
16
%
 
(49,821
)
 
(85
%)
Other Services
 
(4,735
)
 
777

 
(1
%)
 
0
%
 
(5,512
)
 
(709
%)
Gross profit
 
4,228

 
59,561

 
1
%
 
16
%
 
(55,333
)
 
(93
%)
Depreciation and amortization
 
100,979

 
69,547

 
24
%
 
19
%
 
31,432

 
45
%
Selling, general and administrative expenses
 
53,155

 
26,081

 
13
%
 
7
%
 
27,074

 
104
%
(Gain) on disposal of assets
 
(387
)
 
(270
)
 
0
%
 
0
%
 
(117
)
 
43
%
Impairment
 
185

 
3,914

 
0
%
 
1
%
 
(3,729
)
 
(95
%)
Operating loss
 
(149,704
)
 
(39,711
)
 
(36
%)
 
(11
%)
 
(109,993
)
 
277
%
Other income, net
 
916

 
(1,481
)
 
0
%
 
0
%
 
2,397

 
(162
%)
Interest expense
 
(38,299
)
 
(23,450
)
 
(9
%)
 
(6
%)
 
(14,849
)
 
63
%
Total other expenses
 
(37,383
)
 
(24,931
)
 
(9
%)
 
(7
%)
 
(12,452
)
 
50
%
Income tax expense
 

 

 
0
%
 
0
%
 

 
%
Net loss
 
$
(187,087
)
 
$
(64,642
)
 
(44
%)
 
(18
%)
 
$
(122,445
)
 
189
%
 
 
 
 
 
 
 
 
 
 
 
 
 
Revenue.     Total revenue is comprised of revenue from Completion Services and Other Services. Revenue in 2016 increased by $54.4 million, or 15%, to $420.6 million from $366.2 million in 2015. This change in revenue by reportable segment is discussed below.
Completion Services:     Completion Services segment revenue increased by $47.0 million, or 13%, to $410.9 million in 2016 from $363.8 million in 2015. This change was primarily attributable to a 100% growth in the number of deployed hydraulic fracturing fleets, as a result of increased utilization of our combined asset base following our acquisition of the Acquired Trican Operations. This increase was offset by a 43% decrease in the revenue per deployed hydraulic fracturing fleet as a result of competitive pricing driven by current market conditions.
Other Services:     Other Services segment revenue increased by $7.4 million, or 316%, to $9.7 million in 2016 from $2.3 million in 2015. The change was primarily attributable to revenues from the coiled tubing and cementing divisions acquired in connection with the Acquired Trican Operations in 2016. This increase was offset by a $2.3 million reduction in revenues from the drilling division, which was idled in May 2015, as a result of the significant decrease in rig count.
Cost of services.     Cost of services in 2016 increased by $109.7 million, or 36%, to 416.3 million from $306.6 million in 2015. This increase was driven by higher activity in the Completion Services segment, increased

53



costs in connection with a prolonged completion timeline driven by customer completion delays and increased maintenance costs associated with higher-pressure jobs. In addition, in 2016, we had one-time costs of $23.9 million, consisting of acquisition and integration costs of approximately $13.9 million associated with the Acquired Trican Operations and commissioning costs of approximately $10.0 million, including labor and maintenance, to deploy idle hydraulic fracturing fleets and coiled tubing units acquired from Trican. These increases were partially offset by our cost saving initiatives as described below. Costs of services as a percentage of total revenue for in 2016 was 99%, which represented an increase of 15% from 2015. Excluding one-time costs of $23.9 million (described above) and $1.4 million in 2016 and 2015, respectively, total costs of services was $392.4 million and $305.2 million in 2016 and 2015, or 93% and 83% of revenue, respectively, an increase as a percentage of revenue of 10%.
Cost of services, as a percentage of total revenue is presented below:
 
 
Year Ended December 31,
Description
 
2016
 
2015
 
% Change
Segment cost of services as a percentage of segment revenue:
 
 
 
 
 
 
Completion Services
 
98
%
 
84
%
 
14
%
Other Services
 
149
%
 
67
%
 
82
%
Total cost of services as a percentage of total revenue
 
99
%
 
84
%
 
15
%
 
 
 
 
 
 
 
The change in cost of services by reportable segment is further discussed below.
Completion Services:     Completion Services segment cost of services increased by $96.9 million, or 32%, to $401.9 million in 2016 from $305.0 million in 2015. As a percentage of segment revenue, total cost of services was 99% and 84%, in 2016 and 2015, respectively, an increase as a percentage of revenue of 15%. The increase in segment cost of services was driven by higher activity coupled with longer lateral segments and increased proppant volume and increased maintenance costs associated with higher-pressure jobs. In addition, in 2016, we had one-time costs of $22.8 million, consisting of acquisition and integration costs of approximately $13.5 million associated with the Acquired Trican Operations and commissioning costs of approximately $9.3 million, including labor and maintenance, to deploy idle hydraulic fracturing fleets acquired from Trican. These increases were partially offset by cost saving initiatives to drive down supply and material costs through negotiated price concessions from vendors, management of labor costs and our fixed cost structure through facility consolidation and other cost saving initiatives related to shipping and equipment costs. Excluding one-time costs of $22.8 million and $0.9 million in 2016 and 2015, respectively, Completion Services segment costs of services was $379.1 million and $304.2 million in 2016 and 2015, or 92% and 84% of segment revenue, respectively, an increase as a percentage of revenue of 8%.
Other Services:     Other Services segment cost of services increased by $12.9 million, or 826%, to $14.5 million in 2016 from $1.6 million in 2015. The increase was primarily attributable to cost of services in connection with the deployment of, and increased headcount related to, our coiled tubing and cementing operations acquired from Trican, which included one-time integration and commissioning costs of $1.1 million. This increase was partially offset by the $0.6 million decrease of cost of services related to the idling of our drilling services in May 2015. We idled our cementing services and coiled tubing division in April 2016 and December 2016, respectively. All associated overhead has been re-allocated to the Completion Services segment or eliminated. Excluding one-time costs of $1.1 million in 2016 described above, and $0.5 million in 2015, Other Services segment costs of services was $13.3 million and $1.1 million in 2016 and 2015, or 137% and 46% of segment revenue, respectively, which is an increase as a percentage of segment revenue of 91%. This increase was a result of unfavorable absorption of fixed costs on low revenue as coiled tubing was a new division acquired as part of the Acquired Trican Operations.
Depreciation and amortization.     Depreciation and amortization expense increased by $31.4 million, or 45%, to $101.0 million in 2016 from $69.5 million in 2015. This increase was primarily attributable to additional

54



depreciation and amortization expense of $42.1 million related to the property and equipment included in the Acquired Trican Operations. This increase was partially offset by a decrease in depreciation expense of Keane’s existing equipment due to some assets becoming fully depreciated and reduced capital expenditures in 2016.
Selling, general and administrative expense.     SG&A expense increased by $27.1 million, or 104%, to $53.2 million in 2016 from $26.1 million in 2015. The increase in SG&A expense is related to increased headcount, property taxes and insurance associated with a larger asset base as a result of the Acquired Trican Operations. SG&A as a percentage of total revenue was 13% in 2016 compared with 7% in 2015. Total one-time charges were $26.9 million in 2016 and $3.8 million in 2015, which were primarily related to the acquisition and integration of the Acquired Trican Operations and professional fees incurred in connection with the IPO. These costs were partially offset by a decrease in SG&A expenses of our Canadian subsidiary due to $2.5 million of wind-down costs incurred during 2015, which were no longer recurring during 2016. Excluding one-time costs of $26.9 million and $3.8 million described above, SG&A expense was $26.3 million and $22.3 million in 2016 and 2015, respectively, which represents an increase of 18% primarily driven by the acquisition of the Acquired Trican Operations.
Gain on disposal of assets.     Gain on disposal of assets, in 2016 increased by $0.1 million, or 43%, to a gain of $0.4 million in 2016 from gain of $0.3 million in 2015.
Impairment.     In 2016, we recognized impairment expense of $0.2 million as a result of our non-compete agreement relating to the drilling business within our Other Services segment, due to the fact that this non-compete was no longer expected to generate any future cash flows. In 2015, we recognized impairment expense of $3.9 million, which was comprised of a $2.4 million impairment on indefinite-lived intangible assets in our Completion Services segment as a result of the loss of certain customer relationships related to our acquisition of Ultra Tech Frac Services, LLC (the “UTFS Acquisition”), a $1.2 million impairment on the trade name of our drilling business in our Other Services segment and a $0.3 million impairment on our drilling rig fleet in our Other Services segment.
 Other income (expense), net.     Other income (expense), net, in 2016 increased by $2.4 million, or 162%, to income of $0.9 million in 2016 from expense of $1.5 million in 2015. This increase in was primarily driven by an expense recognized in 2015 related to the forfeiture of a $1.7 million deposit due to the cancellation of a hydraulic fracturing equipment purchase order, which was no longer recurring during 2016.
 Interest expense, net.     Interest expense, net of interest income, increased by $14.8 million, or 63%, to $38.3 million in 2016 from $23.5 million in 2015. This increase was primarily attributable to a $4.9 million increase in interest expense on our Senior Secured Notes due to an increase in the interest rate in accordance with the modified terms of the agreement governing the Senior Secured Notes; $7.0 million interest expense incurred on the 2016 Term Loan Facility in connection with the Trican acquisition; $1.8 million of unrealized and realized losses related to an interest rate swap derivative with all changes in its fair value being recognized within other expenses starting from March 2016, which is the date when hedge accounting was discontinued; and a $3.1 million increase in amortization of debt issuance costs and higher commitment fees incurred on the 2016 ABL Facility. These increases were partially offset by $1.7 million decrease in interest expense as a result of the forgiveness of interest on a $20 million related party loan with KG Fracing Acquisition Corp. and S&K Management Services, LLC, on March 16, 2016.
Net loss.     Net loss was $187.1 million in 2016, as compared with net loss of $64.6 million in 2015. This increase in net loss is due to the changes in revenue and expenses discussed above.
ENVIRONMENTAL MATTERS
We are subject to numerous environmental, legal and regulatory requirements related to our operations worldwide. For information related to environmental matters, see Note (18) (Commitments and Contingencies) to the consolidated and combined financial statements.

55


LIQUIDITY AND CAPITAL RESOURCES
Liquidity represents a company's ability to adjust its future cash flows to meet needs and opportunities, both expected and unexpected.
As of December 31, 2017, we had $96.1 million of cash and $278.5 million of debt, compared to $48.9 million of cash and $272.7 million of debt as of December 31, 2016. In 2017, 2016 and 2015, we had capital expenditures of $189.6 million, $23.5 million and $27.2 million, respectively, exclusive of the cash payment attributable to the acquisition of RockPile on July 3, 2017 of $116.6 million or the Acquired Trican Operations on March 16, 2016 of $203.9 million.
 
 
(Thousands of Dollars)
 
 
Year Ended December 31,
 
 
2017
 
2016
 
2015
Net cash provided by (used) in operating activities
 
$
79,691

 
$
(54,054
)
 
$
37,521

Net cash used in investing activities
 
$
(250,776
)
 
$
(227,161
)
 
$
(26,038
)
Net cash provided by (used in) financing activities
 
$
218,122

 
$
276,633

 
$
(10,518
)
 
 
 
 
 
 
 
Significant sources and uses of cash during 2017
Sources of cash:
Operating activities:
Net cash generated by operating activities in 2017 of $79.7 million was primarily driven by higher utilization of our combined asset base and increased gross profit in our Completion Services segment. We also had proceeds of $2.1 million and $4.2 million from the indemnification settlement with Trican and our insurance company related to the acquisition of the Acquired Trican Operations. See Note (18) (Commitments and Contingencies) of Part II, "Item 8. Financial Statements and Supplementary Data" to the consolidated and combined financial statements.
Investing activities:
Total proceeds of $30.6 million from the sale of assets relating to our facilities in Woodward, Oklahoma and Searcy, Arkansas, certain air compressor units, coiled tubing assets and the twelve workover rigs acquired in the acquisition of RockPile. See Note (7) (Property and Equipment, net) of Part II, "Item 8. Financial Statements and Supplementary Data" to the consolidated and combined financial statements.
Financing activities:
Cash provided from IPO proceeds, $255.5 million. See Note (1)(a) Initial Public Offering of Part II, "Item 8. Financial Statements and Supplementary Data" to the consolidated and combined financial statements.
The 2017 Term Loan Facility, entered into on March 15, 2017, provided for $145.0 million, net of associated origination and other transactions fees. Proceeds received were primarily used to fully repay our Senior Secured Notes. See Note (8) Long-Term Debt of Part II, "Item 8. Financial Statements and Supplementary Data" to the consolidated and combined financial statements.
The Incremental Term Loan Facility, entered into on July 3, 2017, provided for $131.1 million, net of associated origination and other transaction fees. Proceeds received were

56


primarily used to fund the acquisition of RockPile. See Note (8) (Long-Term Debt) of Part II, "Item 8. Financial Statements and Supplementary Data" to the consolidated and combined financial statements.
Uses of cash:
Investing activities:
Cash consideration of $116.6 million associated with the acquisition of RockPile, inclusive of a $7.8 million net working capital settlement.
Cash used for capital expenditures of $164.4 million, associated with maintenance capital spend on active fleets, commissioning costs associated with the deployment of our idle fleets, the newbuild acquired as part of the acquisition of RockPile and deposits on new equipment. This activity primarily related to our Completion Services segment.
Financing activities: Cash used to repay our debt facilities, including capital leases but excluding interest, in 2017 was $310.8 million. We used a portion of our IPO proceeds and the proceeds of the 2017 Term Loan Facility to repay our 2016 Term Loan Facility and Senior Secured Notes.
Significant sources and uses of cash during the twelve months ended December 31, 2016
Sources of cash:
Investing activities: Total net proceeds of $0.7 million primarily related to the sale of assets from our idled drilling division within our Other Services segment.
Financing activities: Net cash provided from a capital contribution from shareholders of $200.0 million and the net proceeds from our 2016 Term Loan Facility of $91.2 million. See Note (8) (Long-Term Debt) of Part II, "Item 8. Financial Statements and Supplementary Data" to the consolidated and combined financial statements.
Uses of cash:
Operating activities: Net cash used in operating activities of $54.1 million was primarily attributable to competitive pricing pressure as a result of market conditions, combined with the acquisition, integration and commissioning costs of approximately $47.3 million associated with the acquisition of the Acquired Trican Operations.
Investing activities:
Cash consideration of $205.4 million associated with the acquisition of the Acquired Trican Operations.
Cash used for capital expenditures of $23.5 associated with maintenance capital spend on active fleets, commissioning costs associated with the deployment of our idle fleets.
Financing activities: Cash used to repay and service our debt facilities, including prepayment penalties and capital leases but excluding interest, in 2016 was $8.8 million.
Significant sources and uses of cash during the twelve months ended December 31, 2015
Sources of cash:
Operating activities: Net cash provided by operating activities of $37.5 million was primarily attributable to positive operating results generated by our Completion Services segment, as well as cash generated by working capital changes.

57


Investing activities: Total net proceeds of $1.3 million primarily related to the sale of assets from our idled drilling division within our Other Services segment.
Uses of cash:
Investing activities: Net cash used for investing activities of $27.2 million was primarily related to final payments upon delivery for our newbuild fleet, coupled with maintenance capital expenditures to support our active fleets.
Financing activities: Net cash used in financing activities was primarily related to repay and service our debt facilities, including capital leases but excluding interest, of $6.9 million and a final contingent consideration payment of $2.5 million made in February 2015 in connection with the acquisition of Ultra Tech Frac Services, LLC.
Future sources and use of cash
Capital expenditures for 2018 will be related to maintenance capital spend to support our existing active fleets and the completion of the three newbuild hydraulic fracturing fleets of approximately 150,000 hydraulic horsepower and three wireline spreads, which are anticipated to be delivered in the second and third quarters of 2018. We anticipate our capital expenditures will be funded by cash flows from operations. We currently estimate that our capital expenditures for 2018 will range between $230.0 million and $240.0 million.
Debt service for the twelve months period ended December 31, 2018 is projected to be $31.5 million. We anticipate our debt service will be funded by cash flows from operations.
On February 26, 2018, we announced that our Board of Directors has authorized a stock repurchase program of up to $100.0 million of the Company’s outstanding common stock, with the intent of returning value to our shareholders as we continue to expect further growth and profitability. The duration of the stock buy-back program will be 12 months. The program does not obligate us to purchase any particular number of shares of common stock during any period, and the program may be modified or suspended at any time at our discretion.
Other factors affecting liquidity
Financial position in current market. As of December 31, 2017, we had $96.1 million of cash and a total of $199.7 million available under our revolving credit facility. Furthermore, we have no material adverse change provisions in our bank agreements, and our debt maturities extend over a long period of time. We currently believe that our cash on hand, cash flow generated from operations and availability under our revolving credit facility will provide sufficient liquidity for at least the next 12 months, including for capital expenditures, debt service, working capital investments, contingent liabilities and stock repurchase.
Guarantee agreements. In the normal course of business, we have agreements with a financial institution under which $2.0 million of letters of credit were outstanding as of December 31, 2017.
Customer receivables. In line with industry practice, we bill our customers for our services in arrears and are, therefore, subject to our customers delaying or failing to pay our invoices. The majority of our trade receivables have payment terms of 30 days or less. In weak economic environments, we may experience increased delays and failures to pay our invoices due to, among other reasons, a reduction in our customers’ cash flow from operations and their access to the credit markets, as well as unsettled political conditions. If our customers delay paying or fail to pay us a significant amount of our outstanding receivables, it could have a material adverse effect on our liquidity, consolidated results of operations and consolidated financial condition.

58


Contractual Obligations
In the normal course of business, we enter into various contractual obligations that impact or could impact our liquidity. The table below contains our known contractual commitments as of December 31, 2017.
(Thousands of Dollars)

Contractual obligations
 
Total
 
2018
 
2019-2021
 
2022-2024
 
2025+
Long-term debt, including current portion(1)
 
$
283,200

 
$
2,850

 
$
8,550

 
$
271,800

 
$

Estimated interest payments(2)
 
108,841

 
23,559

 
70,726

 
14,556

 

Capital lease obligations(3)
 
8,518

 
3,633

 
4,885

 

 

Operating lease obligations(4)
 
47,572

 
16,173

 
26,608

 
4,791

 

Purchase commitments(5)
 
211,957

 
133,070

 
78,887

 

 

Equity method investment
 
1,138

 
1,138

 

 

 

Legal contingency
 
4,250

 
4,250

 

 

 

 
 
$
665,476

 
$
184,673

 
$
189,656

 
$
291,147

 
$

 
 
 
 
 
 
 
 
 
 
 
(1)
Long-term debt excludes interest payments on each obligation and represents our obligations under our New Term Loan Facility. In addition, these amounts exclude $8.1 million of unamortized debt discount and debt issuance costs.
(2)
Estimated interest payments are based on debt balances outstanding as of December 31, 2017 and include interest related to the New Term Loan Facility. Interest rates used for variable rate debt are based on the prevailing current London Interbank Offer Rate (LIBOR).
(3)
Capital lease obligations consist of obligations on our capital leases of hydraulic fracturing equipment with CIT Finance LLC and light weight vehicles with ARI Financial Services Inc and includes interest payments.
(4)
Operating lease obligations are related to our real estate, rail cars and light duty vehicles with ARI Financial Services Inc, Enterprise FM Trust, PNC Bank, Anderson Rail Group, CIT Bank, Compass Rail VIII, SMBC Rail Services and Trinity Industries Leasing Company.
(5)
Purchase commitments primarily relate to our agreements with vendors for sand purchases and deposits on equipment. The purchase commitments to sand suppliers represent our annual obligations to purchase a minimum amount of sand from vendors. If the minimum purchase requirement is not met, the shortfall at the end of the year is settled in cash or, in some cases, carried forward to the next year.
Principal Debt Agreements
2017 ABL Facility
On February 17, 2017, Keane Group Holdings, LLC, Keane Frac, LP and KS Drilling, LLC (together with Keane Group Holdings, LLC, Keane Frac, LP and each other person that becomes an ABL Borrower under the 2017 ABL Facility (as defined herein) in accordance with the terms thereof, collectively, the “ABL Borrowers”) and the ABL Guarantors (as defined below) entered into an asset-based revolving credit agreement (the “February 2017 ABL Facility”) with each lender from time to time party thereto (the “2017 ABL Lenders”) and Bank of America, N.A., as administrative agent and collateral agent. The following is a summary of the material provisions of the 2017 ABL Facility. It does not include all of the provisions of the 2017 ABL Facility, does not purport to be complete and is qualified in its entirety by reference to the 2017 ABL Facility described.
Structure. As of September 30, 2017, the February 2017 ABL Facility provided for a $150.0 million revolving credit facility (with a $20.0 million sub-facility for letters of credit), subject to a borrowing base (as described below). On December 22, 2017, we entered into an amended and restated February 2017 ABL Facility (the “Amended 2017 ABL Facility and, together with the February 2017 ABL Facility, the “2017 ABL Facility”). The Amended 2017 ABL Facility among other things, increased the total amount of aggregate commitments by an additional $150.0 million. As a result, the 2017 ABL Facility provided for a $300.0 million revolving credit facility (with a $20.0 million subfacility for letters of credit), subject to a borrowing base (as described below). In addition, subject to approval by the applicable lenders and other customary conditions, the 2017 ABL Facility allows for an additional increase in commitments of up to $150.0 million.

59


Maturity. The loans arising under the initial commitments under the 2017 ABL Facility mature on December 22, 2022. The loans arising under any tranche of extended loans or additional commitments mature as specified in the applicable extension amendment or increase joinder, respectively.
Borrowing Base. Pursuant to the terms of the 2017 ABL Facility, the amount of loans and letters of credit available under the 2017 ABL Facility is limited to, at any time of calculation, an amount equal to (a) 85% multiplied by the amount of eligible billed accounts; plus (b) 80% multiplied by the amount of eligible unbilled accounts; provided, that the amount attributable to clause (b) may not exceed 20% of the borrowing base (after giving effect to any reserve, this limitation and the limitation set forth in the proviso in clause (c)); plus (c) the lesser of (i) 70% of the cost and (ii) 85% of the appraised value of eligible inventory and eligible frac iron; provided, that the amount attributable to clause (c) may not exceed 15% of the borrowing base (after giving effect to any reserve, this limitation and the limitation set forth in the proviso in clause (b)); minus (d) the then applicable amount of all reserves.
Interest. Pursuant to the terms of the 2017 ABL Facility, amounts outstanding under the 2017 ABL Facility bear interest at a rate per annum equal to, at Keane Group’s option, (a) the base rate, plus an applicable margin equal to (x) if the average excess availability is less than 33%, 1.00%, (y) if the average excess availability is greater than or equal to 33% but less than 66%, 0.75% or (z) if the average excess availability is greater than or equal to 66%, 0.50%, or (b) the adjusted London Interbank Offered Rate (“LIBOR”) rate for such interest period, plus an applicable margin equal to (x) if the average excess availability is less than 33%, 2.00%, (y) if the average excess availability is greater than or equal to 33% but less than 66%, 1.75% or (z) if the average excess availability is greater than or equal to 66%, 1.50%. The average excess availability is set on the first day of each full fiscal quarter ending after December, 22, 2017. On or after June 22, 2018, at any time when Consolidated EBITDA (as defined herein) as of the then most recently ended four fiscal quarters for which financial statements are required to be delivered is greater than or equal to $250.0 million, the applicable margin will be reduced by 0.25%; provided that if Consolidated EBITDA is less than $250.0 million as of a later four consecutive fiscal quarters, the applicable margin will revert to the levels set forth above.
Guarantees. Subject to certain exceptions as set forth in the definitive documentation for the 2017 ABL Facility, the amounts outstanding under the 2017 ABL Facility are guaranteed by KGI, KGH Intermediate Holdco I, LLC, KGH Intermediate Holdco II, LLC, Keane Frac GP, LLC, each ABL Borrower (other than with respect to its own obligations) and each subsidiary of KGI that will be required to execute and deliver a facility guaranty after February 17, 2017 (collectively, the “ABL Guarantors”).
Security.     Subject to certain exceptions as set forth in the definitive documentation for the 2017 ABL Facility, the obligations under the 2017 ABL Facility are (a) secured by a first-priority security interest in and lien on substantially all of the accounts receivable, inventory and frac iron equipment; certain other assets and property thereto, including chattel paper, instruments, certain investment property, documents, letter of credit rights, payment intangibles, general intangibles, commercial tort claims, books and records and supporting obligations of the Company and its subsidiaries that are ABL Borrowers or ABL Guarantors under the 2017 ABL Facility (collectively, the “2017 ABL Facility Priority Collateral”) and (b) subject to certain exceptions, secured on a second-priority security interest in and lien on substantially all of the assets of KGI and the ABL Guarantors to the extent not constituting 2017 ABL Facility Priority Collateral.
Fees. Certain customary fees are payable to the lenders and the agents under the 2017 ABL Facility.
Restricted Payment Covenant. The 2017 ABL Facility includes a covenant restricting our ability to pay dividends and make certain other restricted payments, subject to certain exceptions. The 2017 ABL Facility provides that KGI may make cash dividends and other restricted payments in an aggregate amount not to exceed $25.0 million in any four consecutive fiscal quarter period, and to the extent Consolidated EBITDA in any four consecutive fiscal quarter period equals or exceeds $350.0 million, such amount is increased to $50.0 million for so long as Consolidated EBITDA continues to equal or exceed such threshold. Additionally, KGI may make additional cash dividends and other restricted payments to the extent no event of default exists or results therefrom and either (x) excess availability under the 2017 ABL Facility equals or exceeds the greater of (i) 17.5% of the lesser of the

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aggregate commitments and the borrowing base and (ii) $30.0 million, before and after the making of any cash dividend or other restricted payment, and on a pro forma basis for the preceding 45 calendar day period, and the Consolidated Fixed Charge Coverage Ratio (as defined herein) is at least 1.0 to 1.0, or (y) excess availability equals or exceeds the greater of (i) 20% of the lesser of the aggregate commitments and the borrowing base and (ii) $35.0 million, before and after the making of any cash dividend or other restricted payment, and on a pro forma basis for the preceding 45 calendar day period.
“Consolidated EBITDA”, generally, is defined as net income plus reductions to net income attributable to interest, taxes, depreciation and amortization and certain other non-cash charges, including, subject to certain limitations, the addition of run-rate cost savings, operating expense reductions, restructuring charges and expenses and cost saving synergies, and acquisition, integration and divestiture costs and fleet commissioning costs.
“Consolidated Fixed Charge Coverage Ratio”, generally is defined as the ratio of (a) Consolidated EBITDA for the applicable period, minus certain capital expenditures and income taxes paid in cash during such period to (b) interest charges paid or required to be paid in cash, plus scheduled principal payments on certain indebtedness required to be made in cash, plus certain regularly scheduled restricted payments paid in cash, plus restricted payments made using the general restricted payments basket during such period.
Affirmative and Negative Covenants. The 2017 ABL Facility contains various other affirmative and negative covenants (in each case, subject to customary exceptions as set forth in the definitive documentation for the 2017 ABL Facility).
Financial Covenants. Pursuant to the terms of the 2017 ABL Facility, the 2017 ABL Facility requires that the consolidated fixed charge coverage ratio not be lower than 1.0:1.0 as of the last day of the most recently completed four consecutive fiscal quarters for which financial statements were required to have been delivered The Consolidated Fixed Charge Coverage Ratio will only be tested upon the occurrence of an event or default or if excess availability (or liquidity if no loan or letter of credit, other than any letter of credit that has been cash collateralized, is outstanding) is less than the greater of (i) 10% of the loan cap and (ii) $20.0 million at any time.
Events of Default.     The 2017 ABL Facility contains customary events of default (subject to exceptions, thresholds and grace periods as set forth in the definitive documentation for the 2017 ABL Facility).
New Term Loan Facility
On March 15, 2017, Keane Group, Keane Frac, LP and KS Drilling, LLC (together with Keane Group, Keane Frac, LP and each other person that becomes a New Term Loan Borrower under the New Term Loan Facility in accordance with the terms thereof, collectively, the “New Term Loan Borrowers”) and the New Term Loan Guarantors (as defined below) entered into a term loan facility (the “2017 Term Loan Facility”) with each lender from time to time party thereto and Owl Rock, as administrative agent and collateral agent. On the RockPile Closing Date, the New Term Loan Borrowers and the New Term Loan Guarantors (as defined below) entered in an incremental term loan facility (the “Incremental Term Loan Facility” and, together with the 2017 Term Loan Facility, collectively, the “New Term Loan Facility”) with each of the incremental lenders party thereto, each of the existing lenders party thereto and Owl Rock, as administrative agent and collateral agent. The following is a summary of the material provisions of the New Term Loan Facility. It does not include all of the provisions of the New Term Loan Facility, does not purport to be complete and is qualified in its entirety by reference to the New Term Loan Facility described.
Structure. The 2017 Term Loan Facility provides for a $150.0 million initial term loan facility and the Incremental Term Loan Facility provides for a $135.0 million incremental term loan facility (collectively, the “Term Loans”). In addition, subject to certain customary conditions, as of July 3, 2017, the New Term Loan Facility allows for additional incremental term loans in an amount equal to the sum of (a) $50.0 million (less certain amounts in connection with permitted notes and subordinated indebtedness), plus (b) an unlimited amount, subject to, in the case of subclause (b), immediately after giving effect thereto, the total net leverage ratio being less than 1.75:1.00.

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Maturity. August 18, 2022 or, if earlier, the stated maturity date of any other term loans or term commitments.
Amortization. The loans under the 2017 Term Loan Facility amortize in quarterly installments equal to 1.00% per annum of the aggregate principal amount of all initial term loans outstanding, commencing with June 30, 2017. The loans under the Incremental Term Loan Facility amortize in quarterly installments equal to (a) the aggregate original principal amount of the loans under the Incremental Term Loan Facility, times (b) the ratio of (x) the amount of all loans under the 2017 Term Loan Facility that are being repaid on such date to (y) the total aggregate principal amount of all loans under the 2017 Term Loan Facility that remained outstanding as of the RockPile Closing Date, but giving pro forma effect to the amortization payment to be made on June 30, 2017, commencing with September 30, 2017.
Interest. The Term Loans bear interest at a rate per annum equal to, at Keane Group’s option, (a) the base rate plus 6.25%, or (b) the adjusted LIBOR rate for such interest period (subject to a 1.00% floor) plus 7.25%. Following an event of default, the Term Loans bear interest at the rate otherwise applicable to such Term Loans at such time plus an additional 2.00% per annum during the continuance of such event of default.
Prepayments. The New Term Loan Facility is required to be prepaid with: (a) 100% of the net cash proceeds of certain asset sales, casualty events and other dispositions, subject to the terms of an intercreditor agreement between the agent for the New Term Loan Facility and the agent for the 2017 ABL Facility and certain exceptions; (b) 100% of the net cash proceeds of debt incurrences or issuances (other than debt incurrences permitted under the New Term Loan Agreement) and (c) 50% (subject to step-downs to zero, in accordance with the Total Net Leverage Ratio (as defined below) of excess cash flow minus certain voluntary prepayments made under the New Term Loan Facility and all voluntary prepayments of loans under the 2017 ABL Facility to the extent the commitments under the 2017 ABL Facility are permanently reduced by such prepayments.
Guarantees. Subject to certain exceptions as set forth in the definitive documentation for the New Term Loan Facility, the amounts outstanding under the New Term Loan Facility are guaranteed by KGI, KGH Intermediate Holdco I, LLC, KGH Intermediate Holdco II, LLC, Keane Frac GP, LLC, each New Term Loan Borrower (other than with respect to its own obligations) and each subsidiary of KGI that will be required to execute and deliver a facility guaranty after March 15, 2017 (collectively, the “New Term Loan Guarantors”).
Security.     Subject to certain exceptions as set forth in the definitive documentation for the New Term Loan Facility, the obligations under the New Term Loan Facility are secured by (a) a first-priority security interest in and lien on substantially all of the assets of the New Term Loan Borrowers and the New Term Loan Guarantors to the extent not constituting 2017 ABL Facility Priority Collateral and (b) a second-priority security interest in and lien on the 2017 ABL Facility Priority Collateral.
Fees. Certain customary fees are payable to the lenders and the agents under the New Term Loan Facility.
Restricted Payment Covenant. The New Term Loan Facility includes a covenant restricting our ability to pay dividends and make certain other restricted payments, subject to certain exceptions. The New Term Loan Facility provides that KGI may make cash dividends and other restricted payments in an aggregate amount not to exceed $25.0 million (subject to reduction based on certain outstanding investments and prepayments of indebtedness) during the term of the facility. If the pro forma Total Net Leverage Ratio (as defined below) is no greater than 3.0 to 1.0 after giving effect to such restricted payment, we can also pay dividends or make other restricted payments up to the amount of the Cumulative Credit (as defined below). Both of these exceptions are also subject to the requirements that there is no event of default and that we have unrestricted cash plus loan availability under the 2017 ABL Facility of at least $35.0 million after the making of any cash dividend or other restricted payment.
“Total Net Leverage Ratio”, generally, is defined as the ratio of (a) the aggregate principal amount of indebtedness in an amount that would be reflected on our balance sheet in accordance with GAAP (but hedging

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exposure is included only for amounts exceeding $5.0 million) minus cash and cash equivalents not to exceed $100.0 million to (b) Consolidated EBITDA (calculated in substantially the same manner as in the 2017 ABL Facility).
“Cumulative Credit”, generally, is defined as an amount equal to the excess cash flow not required to repay the Term Loans plus other customary additions reduced by the amount of Cumulative Credit used prior to such time. However, for so long as the Total Net Leverage Ratio is less than 1.75:1:00 after giving effect to any proposed restricted payments, the amount of Cumulative Credit is unlimited.
Affirmative and Negative Covenants. The New Term Loan Facility contains various affirmative and negative covenants (in each case, subject to customary exceptions as set forth in the definitive documentation for the New Term Loan Facility).
Financial Covenant. The New Term Loan Facility provides that, as of the last day of any month, the sum of (a) unrestricted cash and cash equivalents of the New Term Loan Borrowers and the New Term Loan Guarantors that are deposited in blocked accounts (to the extent required to be subject to blocked account agreements under the New Term Loan Facility) and (b) the aggregate principal amount that is available for borrowing under the 2017 ABL Facility, may not be less than $35.0 million.
Events of Default.     The New Term Loan Facility contains customary events of default (subject to exceptions, thresholds and grace periods as set forth in the definitive documentation for the New Term Loan Facility).
Off-Balance Sheet Arrangements
Except for our normal operating leases, we do not have any material off-balance sheet financing arrangements, transactions or special purpose entities.
Related Party Transactions
 Our board of directors has adopted a written policy and procedures (the “Related Party Policy”) for the review, approval and ratification of the related party transactions by the independent members of the audit and risk committee of our board of directors. For purposes of the Related Party Policy, a “Related Party Transaction” is any transaction, arrangement or relationship or series of similar transactions, arrangements or relationships (including the incurrence or issuance of any indebtedness or the guarantee of indebtedness) in which (1) the aggregate amount involved will or may be reasonably expected to exceed $120,000 in any fiscal year, (2) the company or any of its subsidiaries is a participant, and (3) any Related Party (as defined herein) has or will have a direct or indirect material interest. All Related Party Transactions will be reviewed in accordance with the standards set forth in the Related Party Policy after full disclosure of the Related Party’s interests in the transaction.
 The Related Party Policy defines “Related Party” as any person who is, or, at any time since the beginning of the company’s last fiscal year, was (1) an executive officer, director or nominee for election as a director of the company or any of its subsidiaries, (2) a person with greater than five percent (5%) beneficial interest in the company, (3) an immediate family member of any of the individuals or entities identified in (1) or (2) of this paragraph, and (4) any firm, corporation or other entity in which any of the foregoing individuals or entities is employed or is a general partner or principal or in a similar position or in which such person or entity has a five percent (5%) or greater beneficial interest. Immediate family members (each, a “Family Member”) includes a person’s spouse, parents, stepparents, children, stepchildren, siblings, mothers- and fathers-in-law, sons- and daughters-in-law, brothers- and sisters-in-law and anyone residing in such person’s home, other than a tenant or employee.
 For further details about our transactions with Related Parties, see Note (19) Related Party Transactions of Part II, “Item 8. Financial Statements and Supplementary Data" and Item 13. "Certain Relationships and Related-Party Transactions and Director Independence."

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Critical Accounting Policies and Estimates
The preparation of our consolidated and combined financial statements and related notes to the consolidated and combined financial statements included within Part II, “Item 8. Financial Statements and Supplementary Data” requires us to make estimates that affect the reported amounts of assets, liabilities, revenue and expenses and related disclosures of contingent assets and liabilities. We base these estimates on historical results and various other assumptions believed to be reasonable, all of which form the basis for making estimates concerning the carrying values of assets and liabilities that are not readily available from other sources. Actual results may differ from these estimates.
A critical accounting estimate is one that requires a high level of subjective judgment by management and has a material impact to our financial condition or results of operations. We believe the following are the critical accounting policies used in the preparation of our consolidated and combined financial statements, as well as the significant estimates and judgments affecting the application of these policies. This discussion and analysis should be read in conjunction with our consolidation and combined financial statements and related notes included within Part II, “Item 8. Financial Statements and Supplementary Data.”
Business combinations
We allocate the purchase price of businesses we acquire to the identifiable assets acquired and liabilities assumed based on their estimated fair values. Any excess purchase price over the fair value of the net identifiable assets acquired is recorded as goodwill. We use all available information to estimate fair values, including quoted market prices, the carrying value of acquired assets and assumed liabilities and valuation techniques such as discounted cash flows, multi-period excess earning or income-based-relief-from-royalty methods. We engage third-party appraisal firms to assist in the fair value determination of inventories, identifiable long-lived assets, identifiable intangible assets, as well as any contingent consideration or earn-out provisions that provide for additional consideration to be paid to the seller if certain future conditions are met. These estimates are reviewed during the 12-month measurement period and adjusted based on actual results. The judgments made in determining the estimated fair value assigned to each class of assets acquired and liabilities assumed, as well as asset lives, can materially impact our financial condition or results of operations. See Note (3) Acquisitions of Part II, "Item 8. Financial Statements and Supplementary Data" for further discussion on our recently completed acquisitions during the years ended December 31, 2017 and 2016.
Legal and environmental contingencies
From time to time, we are subject to legal and administrative proceedings, settlements, investigations, claims and actions, as is typical of the industry. These claims include, but are not limited to, contract claims, environmental claims, employment related claims, claims alleging injury or claims related to operational issues. Our assessment of the likely outcome of litigation matters is based on our judgment of a number of factors, including experience with similar matters, past history, precedents, relevant financial information and other evidence and facts specific to the matter. We accrue for contingencies where the occurrence of a material loss is probable and can be reasonably estimated, based on our best estimate of the expected liability. The estimate of probable costs related to a contingency is developed in consultation with internal and outside legal counsel representing us. The accuracy of these estimates is impacted by, among other things, the complexity of the issues and the amount of due diligence we have been able to perform. Differences between the actual settlement costs, final judgments or fines from our estimates could have a material adverse effect on our financial position or results of operations. See Note (18) Commitments and Contingencies of Part II, "Item 8. Financial Statements and Supplementary Data" for further discussion of our legal, environmental and other regulatory contingencies for the years ended December 31, 2017, 2016 and 2015.
Valuation of long-lived assets, indefinite-lived assets and goodwill
We assess our long-lived assets, such as definite-lived intangible assets and property and equipment, for impairment whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable.

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We assess our goodwill and indefinite-lived assets for impairment annually, as of October 31, or whenever events or circumstances indicate that the carrying amount of goodwill or the indefinite-lived assets may not be recoverable. If the carrying value of an asset exceeds its fair value, we record an impairment charge that reduces our earnings.
We perform our qualitative assessments of the likelihood of impairment by considering qualitative factors relevant to each of our reporting segments, such as macroeconomic, industry, market or any other factors that have a significant bearing on fair value. The expected future cash flows used for impairment reviews and related fair value calculations are based on subjective, judgmental assessments of projected revenue growth, fleet count, utilization, gross margin rates, SG&A rates, working capital fluctuations, capital expenditures, discount rates and terminal growth rates. Many of these judgments are driven by crude oil prices. If the crude oil market declines and remains at low levels for a sustained period of time, we would expect to perform our impairment assessments more frequently and could record impairment charges.
See Note (2)(j) Goodwill and Indefinite-Lived Intangible Assets and (2)(k) Long-Lived Assets of Part II, "Item 8. Financial Statements and Supplementary Data" for further discussion on our impairment assessments of our long-lived assets, indefinite-lived assets and goodwill for the years ended December 31, 2017, 2016 and 2015.
Income Taxes
We account for income taxes in accordance with ASC 740, “Income Taxes,” which requires an asset and liability approach for financial accounting and reporting of income taxes. Under ASC 740, income taxes are accounted for based upon the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis and operating loss carry-forwards using enacted tax rates in effect in the year the differences are expected to reverse. We estimate our annual effective tax rate at each interim period based on the facts and circumstances available at that time, while the actual effective tax rate is calculated at year-end. Our effective tax rates will vary due to changes in estimates of our future taxable income or losses, fluctuations in the tax jurisdictions in which we operate and favorable or unfavorable adjustments to our estimated tax liabilities related to proposed or probable assessments. As a result, our effective tax rate may fluctuate significantly on a quarterly or annual basis.
 In evaluating our ability to recover our deferred tax assets, we consider all available positive and negative evidence, including scheduled reversals of deferred tax liabilities, projected future taxable income, tax planning strategies and recent financial operations. In addition to the Company’s historical financial results, we consider forecasted market growth, earnings and taxable income, the mix of earnings in the jurisdictions in which we operate and the implementation of prudent and feasible tax planning strategies. These assumptions require significant judgment about the forecasts of future taxable income and are consistent with the plans and estimates we use to manage our underlying businesses. We establish a valuation allowance against the carrying value of deferred tax assets when we determine that it is more likely than not that the asset will not be realized through future taxable income. Such amounts are charged to earnings in the period in which we make such determination. Likewise, if we later determine that it is more likely than not that the net deferred tax assets would be realized, we will reverse the applicable portion of the previously provided valuation allowance.
We calculate our income tax liability based on estimates and assumptions that could differ from the actual results reflected in income tax returns filed during the subsequent year. Significant judgment is required in assessing, among other things, the timing and amounts of deductible and taxable items. Due to the complexity of some of these uncertainties, the ultimate resolution may result in payment that is materially different from our current estimate of its tax liabilities. These differences are reflected as increases or decreases to income tax expense in the period in which they are determined.
The amount of income tax we pay is subject to ongoing audits by federal and state tax authorities, which may result in proposed assessments. Our estimate for the potential outcome for any uncertain tax issue is highly judgmental. We believe we have adequately provided for any reasonably foreseeable outcome related to these matters. However, our future results may include favorable or unfavorable adjustments to our estimated tax liabilities in the period the assessments are made or resolved or when statutes of limitation on potential assessments

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expire. Additionally, the jurisdictions in which our earnings or deductions are realized may differ from our current estimates. We recognize interest and penalties, if any, related to uncertain tax positions in income tax expense.
On December 22, 2017, new tax reform legislation, commonly referred to as the Tax Cuts and Jobs Act was signed into law. We evaluated the provisions of the Tax Cuts and Jobs Act and determined only the reduced corporate tax rate from 35% to 21% would have an impact on the consolidated financial statements as of December 31, 2017. Accordingly, we recorded a provision to income taxes for our assessment of the tax impact of the Tax Cuts and Jobs Act on ending deferred tax assets and liabilities and the corresponding valuation allowance. The effects of other provisions of the Tax Cuts and Job Act are not expected to have an adverse impact on our consolidated financial statements. We will continue to analyze the impacts of the Tax Cuts and Jobs Act on the Company and refine our estimates in 2018.
New Accounting Pronouncements
For discussion on the potential impact of new accounting pronouncements issued but not yet adopted, see Note (24) New Accounting Pronouncements of Part II, "Item 8. Financial Statements and Supplementary Data."
NON-GAAP FINANCIAL MEASURES
From time to time in our financial reports, we will use certain non-GAAP financial measures to provide supplemental information that we believe is useful to analysts and investors to evaluate our ongoing results of operations, when considered alongside other GAAP measures such as net income, operating income and gross profit. These non-GAAP measures exclude the financial impact of items management does not consider in assessing Keane's ongoing operating performance, and thereby facilitates review of Keane's operating performance on a period-to-period basis. Other companies may have different capital structures, and comparability to Keane's results of operations may be impacted by the effects of acquisition accounting on our depreciation and amortization. As a result of the effects of these factors and factors specific to other companies, we believe Adjusted EBITDA and Adjusted Gross Profit provide helpful information to analysts and investors to facilitate a comparison of Keane's operating performance to that of other companies.
Adjusted EBITDA is defined as net income (loss) adjusted to eliminate the impact of interest, income taxes, depreciation and amortization, along with certain items management does not consider in assessing ongoing performance. Adjusted Gross Profit is defined as Adjusted EBITDA, further adjusted to eliminate the impact of all activities in the Corporate segment, such as selling, general and administrative expenses, along with cost of services that management does not consider in assessing ongoing performance.


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Item 7A. Quantitative and Qualitative Disclosure About Market Risk
At December 31, 2017, we held no significant derivative instruments that materially increased our exposure to market risks for interest rates, foreign currency rates, commodity prices or other market price risks.
Our material and fuel purchases expose us to commodity price risk. Our material costs primarily include the cost of inventory consumed while performing our stimulation services such as proppant, chemicals and guar. Our fuel costs consist primarily of diesel fuel used by our various trucks and other motorized equipment. The prices for fuel and the raw materials (particularly guar and proppant) in our inventory are volatile and are impacted by changes in supply and demand, as well as ma