Annual Report (10-k)

Date : 02/28/2019 @ 10:56PM
Source : Edgar (US Regulatory)
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Annual Report (10-k)

 

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington D.C. 20549

FORM 10-K

(Mark One)

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

For the fiscal year ended December 31, 2018

OR

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

For the transition period from                     to                

Commission File Number 001-38382

FTS INTERNATIONAL, INC.

(Exact Name of Registrant as Specified in Its Charter)

Delaware

30-0780081

(State or other Jurisdiction of

Incorporation or Organization)

(I.R.S. Employer

Identification No.)

 

 

 

 

777 Main Street, Suite 2900, Fort Worth, Texas

76102

(Address of Principal Executive Offices)

(Zip Code)

 

(817) 862-2000

(Telephone Number, Including Area Code)

Securities registered pursuant to Section 12(b) of the Securities Exchange Act of 1934:

Title of each class

 

Name of each exchange on which registered

Common Stock, par value $0.01 per share

 

New York Stock Exchange

 

Securities registered pursuant to Section 12(g) of the Securities Exchange Act of 1934:

None

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

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes  No

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).  Yes  No

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large Accelerated Filer

 

 

Accelerated Filer

Non-Accelerated Filer

 

 

Smaller reporting company

Emerging growth company

 

 

 

 

 

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  Yes  No

As of June 29, 2018, the last trading day of the registrant’s most recently completed second fiscal quarter, the aggregate market value of the common stock held by non-affiliates of the registrant was approximately $468.2 million, based on the closing price of the registrant’s common stock on that date. As of February 22, 2019, the registrant had 109,794,386 shares of common stock, $0.01 par value, outstanding.

 

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the proxy statement for the registrant’s 2019 annual meeting of stockholders are incorporated by reference in Part III of this Form 10-K.

 

 


 

FTS INTERNATIONAL, INC.

Form 10‑K

Year Ended December 31, 2018

INDEX

 

 

Page

Cautionary Statement Regarding Forward-Looking Statements  

ii

 

 

 

 

 

PART I

1

 

 

 

 

 

Item 1.

Business

1

 

Item 1A.

Risk Factors

12

 

Item 1B.

Unresolved Staff Comments

29

 

Item 2.

Properties

29

 

Item 3.

Legal Proceedings

30

 

Item 4.

Mine Safety Disclosures

30

 

 

 

 

 

PART II

30

 

 

 

 

 

Item 5.

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

30

 

Item 6.

Selected Financial Data

32

 

Item 7.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

35

 

Item 7A.

Quantitative and Qualitative Disclosures About Market Risk

45

 

Item 8.

Financial Statements and Supplementary Data

45

 

Item 9.

Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

45

 

Item 9A.

Controls and Procedures

45

 

Item 9B.

Other Information

46

 

 

 

 

 

PART III

47

 

 

 

 

 

Item 10.

Directors, Executive Officers and Corporate Governance

47

 

Item 11.

Executive Compensation

47

 

Item 12.

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

47

 

Item 13.

Certain Relationships and Related Transactions, and Director Independence

47

 

Item 14.

Principal Accountant Fees and Services

47

 

 

 

 

 

PART IV

47

 

 

 

 

 

Item 15.

Exhibits and Financial Statement Schedules

47

 

 

Index to Consolidated Financial Statements

F-1

 

 

i


 

Cautionary Statement Regarding Forward-Looking Statements

This annual report contains “forward-looking statements” that are subject to risks and uncertainties. All statements other than statements of historical or current fact included in this annual report are forward-looking statements. Forward-looking statements refer to our current expectations and projections relating to our financial condition, results of operations, plans, objectives, strategies, future performance and business. Forward-looking statements may be identified by the fact that they do not relate strictly to historical or current facts. These statements may include words such as “anticipate,” “assume,” “believe,” “can have,” “contemplate,” “continue,” “could,” “design,” “due,” “estimate,” “expect,” “goal,” “intend,” “likely,” “may,” “might,” “objective,” “plan,” “predict,” “project,” “potential,” “seek,” “should,” “target,” “will,” “would” and other words and terms of similar meaning in connection with any discussion of the timing or nature of future operational performance or other events. For example, all statements we make relating to our estimated and projected costs, expenditures and growth rates, our plans and objectives for future operations, growth or initiatives or strategies are forward-looking statements. All forward-looking statements are subject to risks and uncertainties that may cause actual results to differ materially from those that we expect and, therefore, investors should not unduly rely on such statements. The risks that could cause these forward-looking statements to be inaccurate include but are not limited to:

·

a decline in domestic spending by the onshore oil and natural gas industry;

·

volatility in oil and natural gas prices;

·

customers’ inability to maintain or increase their reserves going forward;

·

deterioration in general economic conditions or a weakening of the broader energy industry;

·

the competitive nature of the industry in which we conduct our business;

·

the effect of a loss of, or financial distress of, one or more significant customers;

·

nonpayment by customers we extend credit to;

·

demand for services in our industry;

·

actions of OPEC, its members and other state-controlled oil companies relating to oil price and production controls;

·

a decline in demand for proppant;

·

our inability to employ a sufficient number of key employees, technical personnel and other skilled or qualified workers;

·

the occurrence of a significant event or adverse claim in excess of the insurance coverage we maintain;

·

fines or penalties (administrative, civil or criminal), revocations of permits, or issuance of corrective action orders for noncompliance with health, safety and environmental laws and regulations;

·

changes in laws and regulations which impose additional requirements or restrictions on business operations;

·

federal, state and local regulation of hydraulic fracturing and other oilfield service activities, as well as exploration and production (“E&P”) activities, including public pressure on governmental bodies and regulatory agencies to regulate our industry;

·

existing or future laws and regulations related to greenhouse gases and climate change;

·

our ability to obtain permits, approvals and authorizations from governmental and third parties, and the effects of or changes to U.S. and foreign government regulation;

·

restrictions on drilling activities intended to protect certain species of wildlife;

·

conservation measures and technological advances which reduce demand for oil and natural gas;

·

the level of global and domestic oil and natural gas inventories;

ii


 

·

the price and availability of alternative fuels and energy sources;

·

the discovery rates of new oil and natural gas reserves;

·

limitations on construction of new natural gas pipelines or increases in federal or state regulation of natural gas pipelines;

·

the availability of water resources, suitable proppant and chemicals in sufficient quantities for use in hydraulic fracturing fluids;

·

the cost of exploring for, developing, producing and delivering oil and natural gas;

·

third party claims for possible infringement of intellectual property rights;

·

introduction of new drilling or completion techniques, or services using new technologies subject to patent or other intellectual property protections;

·

lead times associated with acquiring equipment and products and availability of qualified personnel;

·

loss or corruption of our information or a cyberattack on our computer systems;

·

one or more of our directors may not reside in the United States limiting the ability of investors from obtaining or enforcing judgments against them;

·

adverse weather conditions causing stoppage or delay in operations;

·

a terrorist attack or armed conflict disrupting operations;

·

additional economic, political and regulatory risks related to international operations;

·

geopolitical developments and political instability in oil and natural gas producing countries;

·

our ability to utilize our net operating losses;

·

our inability to service our debt obligations;

·

adverse effects on our financial strategy and liquidity;

·

increases in interest rates; and

·

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

We make many of our forward-looking statements based on our operating budgets and forecasts, which are based upon detailed assumptions. While we believe that our assumptions are reasonable, we caution that it is very difficult to predict the impact of known factors, and it is impossible for us to anticipate all factors that could affect our actual results.

See the “Risk Factors” included in Item 1A of this annual report for a more complete discussion of the risks and uncertainties mentioned above and for discussion of other risks and uncertainties we face that could cause our forward-looking statements to be inaccurate. All forward-looking statements attributable to us are expressly qualified in their entirety by these cautionary statements as well as others made in this annual report and hereafter in our other SEC filings and public communications. All forward-looking statements made by us should be evaluated in the context of these risks and uncertainties.

We caution that the risks and uncertainties identified by us may not be all of the factors that are important to investors. Furthermore, the forward-looking statements included in this annual report are made only as of the date hereof. We undertake no obligation to publicly update or revise any forward-looking statement as a result of new information, future events or otherwise, except as required by law.

 

 

iii


 

PART I

ITEM 1. BUSINESS

General

FTS International, Inc. (the “Company”,  “we”,  “our”) was originally formed in 2000. We are one of the largest providers of hydraulic fracturing services in North America. Our services enhance hydrocarbon flow from oil and natural gas wells drilled by E&P companies in shale and other unconventional resource formations. We have 1.7 million total hydraulic horsepower across 34 fleets, with 19 fleets active and one fleet under construction and awaiting final assembly as of December 31, 2018. Our significant customers have included Anadarko Petroleum Corporation, Ascent Resources Utica Holdings, LLC, Centennial Resource Development, Inc., Chesapeake Energy Corporation, Devon Energy Corporation, Diamondback Energy, Inc., EOG Resources, Inc., EQT Corporation, and other leading E&P companies that specialize in unconventional oil and natural gas resources in North America.

We operate in five of the most active major unconventional basins in the United States: the Permian Basin, the SCOOP/STACK Formation, the Marcellus/Utica Shale, the Eagle Ford Shale and the Haynesville Shale. The following map shows the basins in which we operate and the number of fleets operated in each basin as of January 31, 2019.

PICTURE 1

 

We manufacture and refurbish many of the components used by our fleets, including consumables, such as fluid-ends. We also perform substantially all the maintenance, repair and refurbishment of our hydraulic fracturing fleets, including the reactivation of idle equipment. Our cost to produce components and reactivate fleets is significantly less than the cost to purchase comparable quality components and fleets from third-party suppliers. For example, we manufacture fluid-ends and power-ends at a cost that is approximately 50% less than purchasing them from outside suppliers. In addition, our capabilities allow us to perform full-scale refurbishments of our fracturing units, including refurbishing the engines and transmissions, at a cost that is approximately half the cost of utilizing an original equipment manufacturer or other outside supplier.

We designed and assembled all of our existing fleets using internal resources and are able to assemble new fleets internally at a substantial discount to the cost of buying them new from third-party providers. We have a uniform fleet of high-horsepower hydraulic fracturing equipment, designed for completions work in oil and natural gas basins

1


 

requiring high levels of pressure, flow rate and sand intensity. The standardized, “plug and play” nature of our fleet provides us with several advantages, including: reduced repair and maintenance costs; reduced inventory costs; the ability to redeploy equipment among operating basins; and reduced complexity in our operations, which improves our safety and operational performance.

Our large scale and culture of innovation allows us to take advantage of leading technological solutions. We have been a fast adopter of new technologies focused on: increasing fracturing effectiveness for our customers; reducing the operating costs of our equipment; and enhancing the health, safety, and environmental (“HSE”) conditions at our well sites.

Safety is at the core of our operations. Our safety record over the last three years was the best in our history. We believe our safety record is significantly better than our industry peer group, based on U.S. Bureau of Labor Statistics reports from 2011 through 2017. For the past three years, we believe our total recordable incident rate was less than half of the industry average. Many of our customers impose minimum safety requirements on their suppliers of hydraulic fracturing services, and some of our competitors are not permitted to bid on work for certain customers because they do not meet those customers’ minimum safety requirements. Because safety is important to our customers, our safety score helps our commercial team to win business from our customers. Our safety focus is also a morale benefit for our crews, which enhances our employee retention rates. Finally, we believe that continually searching for ways to make our operations safer is the right thing to do for our employees and our customers.

Our Services

Hydraulic Fracturing

Our primary service offering is providing hydraulic fracturing services, also known as pressure pumping, to oil and natural gas E&P companies. These services are designed to enhance hydrocarbon flow in oil and natural gas wells, thus increasing the amount of hydrocarbons recovered.

The development of resources in unconventional reservoirs, including oil and natural gas shales, is a technically and operationally challenging segment of the oilfield services market that has experienced strong growth worldwide, particularly in the United States.

Oil and natural gas wells are typically divided into one or more “stages,” which are isolated zones that focus the high-pressure fluid and proppant from the hydraulic fracturing fleet into distinct portions of the well and surrounding reservoir. The number of stages that will divide a well is determined by the customer’s proposed job design. Our customers typically measure our operational performance in terms of the number of stages fractured and how well we minimize non-productive time on our jobs. As a result, we believe the average number of stages completed per active fleet in a given period of time is an important operating metric for our business. During the last two years, as a result of our customers trending toward more intense completions, our quarterly average stage length, measured in minutes to complete, has increased by approximately 8%. Despite the longer average stage lengths, we have been able to increase our average stages per active fleet to achieve record levels in 2017 and 2018. We were able to increase our average stage per active fleets because the primary contributor to the number of stages we complete in a quarter is our ability to reduce non-productive time on our equipment, rather than variability in operating basins or formation characteristics.

Hydraulic fracturing represents the largest cost of completing a shale oil or natural gas well. The process consists of pumping a fracturing fluid into a well casing or tubing at sufficient pressure to fracture, or prop open, the formation. The fracturing fluid consists of water and sand, or other proppant, mixed with a small amount of chemicals. Once the pressure opens the fractures, the proppants act as a wedge that keep the fractures open, allowing the trapped hydrocarbons to flow more freely. Our customers are responsible for the disposal of the fracturing fluid that flows back out of the well, and we are not involved in that process or in the disposal of the fluid. As a result of a successful fracturing process, hydrocarbon recovery rates are substantially enhanced; thus, increasing the return on investment for our customer. The amount of hydrocarbons produced from a typical shale oil or natural gas well generally declines quickly. As a result, E&P companies must fracture new wells to maintain production levels.

2


 

Each of our fleets typically consists of 10 to 20 hydraulic fracturing units along with certain ancillary equipment. Our hydraulic fracturing units consist primarily of a high-pressure pump, a diesel or combined diesel and natural gas engine, a transmission and various other supporting equipment mounted on a trailer. The high pressure pump consists of two key assemblies: the fluid-end and the power-end. Although the power-end of our pumps generally lasts several years, the fluid-end, which is the part of the pump through which the fracturing fluid is expelled under high pressure, is a shorter-lasting consumable, typically lasting less than one year. We refer to the group of hydraulic fracturing units, auxiliary equipment and vehicles necessary to perform a typical fracturing job as a “fleet” and the personnel assigned to each fleet as a “crew.” Our fleets operate primarily on a 24-hour-per-day basis, in which we typically staff three crews per fleet, including one crew with the day off. Our focus on 24-hour operations allows us to keep our equipment working for more hours per day, which we believe enhances our return-on-assets over time.

Each hydraulic fracturing fleet includes a mobile, on-site control center that monitors pressures, rates and volumes, as applicable. Each control center is equipped with high bandwidth satellite hardware that provides continuous upload and download of job telemetry data. The data is delivered on a real-time basis to on-site job personnel, the customer and our national operations center for display in both digital and graphical form.

We prefer to enter into service agreements with our customers for one or more “dedicated” fleets, rather than providing our fleets for “spot work.” Under our typical dedicated fleet agreement, we deploy one or more of our hydraulic fracturing fleets exclusively to the customer to follow the customer’s completion schedule and job specifications until the agreement expires or is terminated in accordance with its terms. By contrast, under a typical spot work agreement, the fleet moves between customers as work becomes available. We believe that our strategy of pursuing dedicated fleet agreements leads to higher fleet utilization, as measured by the number of days each fleet is working per month, which we believe reduces our month-to-month revenue volatility and improves our revenue and profitability. See Note 2 —  “Summary of Significant Accounting Policies” in Notes to our Consolidated Financial Statements for discussion of our revenue recognition and pricing under our service agreements.

Wireline Services

Our wireline services primarily consist of setting plugs between hydraulic fracturing stages, creating perforations within hydraulic fracturing stages and logging the characteristics of resource formations. Our wireline services equipment is designed to operate under high pressure in unconventional resource formations without delaying hydraulic fracturing operations.

Other

We own a 45% interest in SinoFTS, which is a Chinese joint venture that we formed in June 2014 with Sinopec Oilfield Service Corporation (“Sinopec”) to provide hydraulic fracturing services in China. On January 9, 2019, we filed an arbitration proceeding with the Singapore International Arbitration Centre to resolve a dispute related to the manner of operations by our JV partner.

Our Strategy 

Our primary business objective is to be the largest pure-play provider of hydraulic fracturing services within U.S. unconventional resource basins. We intend to achieve this objective through the following strategies:

Maintain a disciplined approach that optimizes cash flow

All levels of our organization focus on providing the safest work environment for our employees and on generating the highest level of profitability and cash generation as possible, within the limitations of industry conditions.

We focus on operating our equipment at the highest level of efficiency to maximize billing activity for each of our fleets, which is often measured in terms of stages completed per active fleet. In turn, we strive to charge a competitive rate to our customer and to be compensated for the high level of efficiency that we provide. This ultimately leads to an overall lower cost of production for our customer.

3


 

In addition, we are a cost focused organization that embraces innovation to continually find ways to lower the cost to operate our business. This is enabled by our culture and our in-house manufacturing capabilities, which allow us to continuously identify and execute improvements in the design and operation of our equipment.

Capitalize on an increased demand for our services with quick deployment and low cost fleet reactivations

We believe the demand for hydraulic fracturing is strong and will continue to grow into the future as more customers focus on the development of their onshore resources.  We believe that the cost per barrel of oil from unconventional onshore production is one of the lowest in the United States, and, as a result, E&P capital has shifted towards this type of production. Industry reports have forecasted that the number of horizontal wells drilled in the United States will continue to increase. In addition, the sand utilized in the completion of a horizontal well has more than doubled since 2014 as operators continue to innovate to find the optimal job design. As one of the largest hydraulic fracturing service providers in North America, we believe we are well positioned to capitalize on the continued increase in the onshore oil and natural gas E&P market.

We have 1.7 million total hydraulic horsepower across 34 total fleets, with 19 fleets active and one fleet under construction and awaiting final assembly as of December 31, 2018. We believe our in-house manufacturing capabilities allow us to reactivate equipment quicker and at a lower cost than competitors.

Deepen and expand relationships with customers that value our completions efficiency

We service our customers primarily with dedicated fleets and 24-hour operations. We dedicate one or more of our fleets exclusively to the customer for a period of time, allowing for those fleets to be integrated into the customer’s drilling and completion schedule. As a result, we are able to achieve higher levels of utilization, as measured by the number of days each fleet is working per month, which increases our profitability. In addition, we operate our fleets on a 24-hour basis, allowing us to complete our services more efficiently with the least amount of non-productive time. Accordingly, we seek to partner with customers that have a large number of wells needing completion and that value efficiency in the performance of our service. Specifically, we target customers whose completions activity typically involves minimal non-productive time between stages, a high number of stages per well, multiple wells per pad and a short distance from one well pad site to the next. This strategy aligns with the strategy of many of our customers, who are trying to achieve a manufacturing-style model of drilling and completing wells in a sequential pattern to maximize effective acreage. We plan to leverage this strategy to expand our relationships with our existing customers as we continue to attract new customers.

Capitalize on our uniform fleet, leading scale and significant basin diversity to provide superior performance with reduced operating costs

We primarily serve large independent E&P companies that specialize in unconventional oil and natural gas resources in North America. Because we operate for customers with significant scale in each of our operating basins, we have the diversity to react to and benefit from positive activity trends in any basin with a balanced exposure to oil and natural gas. Our uniform fleet allows us to cost-effectively redeploy equipment and fleets among existing operating basins to capture the best pricing and activity trends. The uniform fleet is easier to operate and maintain, resulting in reduced non-productive time as well as lower training costs and inventory stocking requirements. Our geographic breadth also provides us with opportunities to capitalize on customer relationships in one basin in order to win business in other basins in which the customer operates. We intend to leverage our scale, standardized equipment and cost structure to gain market share and win new business.

Rapidly adopt new technologies in a capital efficient manner

Our large scale and culture of innovation allow us to take advantage of leading technological solutions. We have been a fast adopter of new technologies focused on: increasing fracturing effectiveness for our customers, reducing the operating costs of our equipment and enhancing the HSE conditions at our well sites.

4


 

Recent examples of initiatives aimed at reducing our operating costs include: vibration sensors with predictive maintenance analytics on our heavy equipment; stainless steel fluid-ends with a longer useful life; the ability to automate certain portions of our operations; and adoption of hardened alloys and lubricant blends for our consumables. Recent examples of initiatives aimed at improving our HSE conditions include: dual fuel engines that can run on both natural gas and diesel fuel; electronic pressure relief systems; spill prevention and containment solutions; dust control mitigation; electronic logging devices; and leading containerized proppant delivery solutions.

Reduce debt and maintain a more conservative capital structure

To improve our financial flexibility, we have been focused on reducing our debt levels and maintaining a sufficient liquidity level. We believe we should be able to not only make the investments necessary to remain a market leader in hydraulic fracturing, but also to continue to strengthen our balance sheet.

Reducing our indebtedness remains a top priority. If we are able to further reduce our indebtedness and continue to generate high levels of cash flow from operations, we could return value to stockholders.

Customers

The customers we serve are primarily large, independent E&P companies that specialize in unconventional oil and natural gas resources in North America. The following table shows the customers that represented more than 10% of our total revenue during the years ended December 31, 2018, 2017 and 2016. The loss of any of our largest existing customers could have a material adverse effect on our results of operations. While we view revenue as an important metric in assessing customer concentration, we also compare and manage our customer portfolio based on the number of fleets we place with each customer.

 

 

 

 

 

 

 

 

Year Ended December 31,

 

 

2018

  

2017

  

2016

 

EQT Production Company

12

%

*

 

12

%

Devon Energy Corporation

12

%

*

 

*

 

Newfield Exploration

*

 

*

 

18

%

EP Energy Corporation

*

 

*

 

11

%

Vine Oil and Gas, L.P.

*

 

*

 

10

%


*Less than 10%.

Suppliers

We purchase some of the parts that we use in the refurbishment and repair of our heavy equipment, such as hydraulic fracturing units and blenders, and in the refurbishment, repair and manufacturing of certain major replacement components of our heavy equipment such as fluid-ends, power-ends, engines, transmissions, radiators and trailers. We do not currently expect significant interruptions in the supply of these materials. While we believe that 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, there can be no assurance that there will be no price or supply issues over the long-term.

When requested by the customer, we also purchase the proppants and chemicals we use in our operations and the diesel fuel for our equipment from a variety of suppliers throughout the United States. To date, we have generally been able to obtain the supplies necessary to support our operations on a timely basis at competitive prices. In the past, we have experienced some delays in obtaining these materials during periods of high demand. We have a long-term supply agreement with one vendor to supply a significant portion of the proppant we procure until 2024. This agreement contains a fixed volume of purchases at market-based variable pricing with minimum unconditional purchase obligations. These minimum purchase obligations can change based upon the vendors’ ability to supply the minimum requirements.

5


 

Competition

The market in which we operate is highly competitive and highly fragmented. Our competition includes multi-national oilfield service companies as well as regional competitors. Our major multi-national competitors are Halliburton Company and Schlumberger Limited, each of which has significantly greater financial resources than we do. Our major domestic competitors are RPC, Inc., Superior Energy Services, ProPetro Holding Corp., Patterson-UTI Energy, Inc., BJ Services, Inc., Liberty Oilfield Services Inc. and Keane Group, Inc. Certain of these competitors provide a number of oilfield services and products in addition to hydraulic fracturing. We also face competition from smaller regional service providers in some of the geographies in which we operate.

Competition in our industry is based on a number of factors, including price, service quality, safety, and in some cases, breadth of products. We believe we consistently deliver exceptional service quality, based in part on the durability of our equipment. Our durable equipment reduces non-productive time due to equipment failure and allows our customers to avoid costs associated with delays in completing their wells. By being able to meet the most demanding pressure and flow rate requirements, our equipment also enables us to operate efficiently in challenging geological environments in which some of our competitors cannot operate effectively.

Cyclical Nature of Industry 

We operate in a highly cyclical industry driven mainly by the level of horizontal drilling activity in the United States, which in turn depends largely on current and anticipated future crude oil and natural gas prices and production decline rates. A critical factor in assessing the outlook for the industry is the supply and demand for both oil and natural gas. Demand for oil and natural gas is subject to large and rapid fluctuations. These fluctuations are driven by commodity demand in the industry and corresponding price increases. When oil and natural gas prices increase, producers generally increase their capital expenditures, which generally results in greater revenues and profits for oilfield service companies. However, increased capital expenditures also ultimately result in greater production, which historically, has resulted in increased supplies and reduced prices that, in turn, tend to reduce demand for oilfield services such as hydraulic fracturing services.

The pricing for our services is also driven by the industry capacity of hydraulic fracturing equipment. Historically, the industry has built additional equipment to supply the increased demand.  When the demand declines, the industry has more equipment than what is needed by customers.  This often leads to a decline in the price for our services until equipment is de-activated and the supply and demand fundamentals are closer to balanced.

For these reasons, our results of operations may fluctuate from quarter to quarter and from year to year, and these fluctuations may distort period-to-period comparisons of our results of operations.

Seasonality

Seasonality has not significantly affected our overall operations. However, toward the end of some years, we experience slower activity in our pressure pumping operations in connection with the holidays and as customers’ capital expenditure budgets are depleted. Similarly, the beginning of some years have a slow start as customers are starting a new capital budget cycle and our operations are more prone to experience winter weather.  Occasionally, our operations have been negatively impacted by severe weather conditions that cause disruption to our supply chain or our ability to transport materials and equipment to the job site.

Employees

At December 31, 2018, we had approximately 1,780 employees. Our employees are not covered by collective bargaining agreements, nor are they members of labor unions. We consider our relationship with our employees to be good.

6


 

Insurance

Our operations are subject to hazards inherent in the oil and natural gas industry, including accidents, blowouts, explosions, 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. 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 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 types and amounts that we believe to be customary and reasonable for our industry. These coverages and retentions address certain risks relating to commercial general liability, workers’ compensation, business auto, property and equipment, directors and officers, environment, pollution and other risks. Although we maintain insurance coverage of types and amounts that we believe to be customary in our industry, we are not fully insured against all risks, either because insurance is not available or because of the high premium costs relative to perceived risk.

Environmental Regulation

Our operations are subject to stringent laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Numerous federal, state and local governmental agencies, such as the U.S. Environmental Protection Agency (the “EPA”), issue regulations that often require difficult and costly compliance measures that carry substantial administrative, civil and criminal penalties and may result in injunctive obligations for non-compliance. In addition, some laws and regulations relating to protection of the environment may, in certain circumstances, impose strict liability for environmental contamination, rendering a person liable for environmental damages and cleanup 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 could have a material adverse effect on our business, financial condition and results of operations.

Hydraulic Fracturing Activities . Certain governmental reviews are either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. For example, in December 2016, the EPA released its final report, entitled “Hydraulic Fracturing for Oil and Gas: Impacts from the Hydraulic Fracturing Water Cycle on Drinking Water Resources in the United States,” on the potential impacts of hydraulic fracturing on drinking water resources. The report states that the EPA found scientific evidence that hydraulic fracturing activities can impact drinking water resources under some circumstances, noting that the following hydraulic fracturing water cycle activities and local- or regional-scale factors are more likely than others to result in more frequent or more severe impacts: water withdrawals for fracturing in times or areas of low water availability; surface spills during the management of fracturing fluids, chemicals or produced water; injection of fracturing fluids into wells with inadequate mechanical integrity; injection of fracturing fluids directly into groundwater resources; discharge of inadequately treated fracturing wastewater to surface waters; and disposal or storage of fracturing wastewater in unlined pits. The report does not make any policy recommendations. These ongoing or proposed studies could spur initiatives to further regulate hydraulic fracturing under the federal Safe Drinking Water Act (“SDWA”) or other regulatory mechanisms. For example, on November 29, 2018, EPA and the State Review of Oil and Natural Gas Environmental Regulation (“STRONGER”) entered into a Memorandum of Understanding pursuant to which EPA and Stronger will collaborate on oil and natural gas exploration and development regulatory programs.

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At the state level, several states have adopted or are considering legal requirements that could impose more stringent permitting, disclosure and well construction requirements on hydraulic fracturing activities. For example, in May 2013, the Railroad Commission of Texas issued a “well integrity rule,” which updates the requirements for drilling, putting pipe down and cementing wells. The rule also includes new testing and reporting requirements, such as (i) the requirement to submit cementing reports after well completion or after cessation of drilling, whichever is later, and (ii) the imposition of additional testing on wells less than 1,000 feet below usable groundwater. The well integrity rule took effect in January 2014. Local governments also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular. Some states, counties and municipalities are closely examining water-use issues, such as permit and disposal options for processed water. If new or more stringent federal, state or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of development activities and perhaps even be precluded from drilling wells. See “Risk Factors—Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays” in Item 1A of this annual report.

Remediation of Hazardous Substances . The Comprehensive Environmental Response, Compensation and Liability Act, as amended, referred to as “ CERCLA ” or the “ Superfund law ,” and comparable state laws generally impose liability, without regard to fault or legality of the original conduct, on certain classes of persons that are considered to be responsible for the release of hazardous substances into the environment. These persons include the current owner or operator of a contaminated facility, a former owner or operator of the facility at the time of contamination and those persons that disposed or arranged for the disposal of the hazardous substances at the facility. Under CERCLA and comparable state statutes, persons deemed “potentially responsible parties” are subject to strict liability that, in some circumstances, may be joint and several for the costs of removing or remediating previously disposed wastes (including wastes disposed of or released by prior owners or operators) or property contamination (including groundwater contamination), for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances released into the environment.

Water Discharges . The Federal Water Pollution Control Act of 1972, as amended, also known as the “ Clean Water Act ,” the Safe Drinking Water Act, the Oil Pollution Act and analogous state laws and regulations issued thereunder impose restrictions and strict controls regarding the unauthorized discharge of pollutants, including produced waters and other natural gas and oil wastes, into navigable waters of the United States, as well as state waters. On December 13, 2016, the EPA released a final report which identified discharge of inadequately treated hydraulic fracturing wastewater to surface water resources as having potential to impact drinking water resources. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the state. Under the Clean Water Act, the EPA has adopted regulations concerning discharges of storm water runoff, which require covered facilities to obtain permits.

These laws and regulations also prohibit certain other activity in wetlands unless authorized by a permit issued by the U.S. Army Corps of Engineers, which we refer to as the Corps. In September 2015, a new rule became effective which was issued by the EPA and the Corps defining the scope of the jurisdiction of the EPA and the Corps over wetlands and other waters of the United States. The rule has been challenged in court on the grounds that it unlawfully expands the reach of Clean Water Act’s programs, and implementation of the rule has been stayed in certain states pending resolution of the court challenge. On February 6, 2018, the EPA and the Corps published a final rule delaying implementation of the rule until February 6, 2020. The February 2018 rule has been challenged in court and is subject to a nationwide injunction. On June 29, 2018, EPA and the Corps published a supplemental notice of proposed rulemaking that solicited public comment on EPA’s and the Corps’ plan to repeal the September 2015 rule. On December 11, 2018, EPA proposed a rule that would revise the definition of “waters of the United States’ and clarify the scope of federal authority under the Clean Water Act. The rapidly changing landscape of federal regulation creates uncertainty in our and our customers’ business. Under the Clean Water Act we are also subject to spill prevention, control and countermeasure plan requirements that require appropriate containment berms and similar structures to help prevent the contamination of navigable waters. Noncompliance with these requirements may result in substantial administrative, civil and criminal penalties, as well as injunctive obligations.

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Waste Handling . Wastes from certain of our operations (such as equipment maintenance and past chemical development, blending, and distribution operations) are subject to the federal Resource Conservation and Recovery Act of 1976 (“RCRA”), and comparable state statutes and regulations promulgated thereunder, which impose requirements regarding the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. With federal approval, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Although certain oil production wastes are exempt from regulation as hazardous wastes under RCRA, such wastes may constitute “solid wastes” that are subject to the less stringent requirements of non-hazardous waste provisions. In the EPA’s 2016 final report on the impacts from hydraulic fracturing on drinking water resources, the EPA identified disposal or storage of hydraulic fracturing wastewater in unlined pits as resulting in contamination of groundwater resources.

Administrative, civil and criminal penalties can be imposed for failure to comply with waste handling requirements. Moreover, the EPA or state or local governments may adopt more stringent requirements for the handling of non-hazardous wastes or categorize some non-hazardous wastes as hazardous for future regulation. Legislation has been proposed from time to time in Congress to re-categorize certain oil and natural gas exploration, development and production wastes as “hazardous wastes.” Several environmental organizations have also petitioned the EPA to modify existing regulations to recategorize certain oil and natural gas exploration, development and production wastes as “hazardous.” Any such changes in the laws and regulations could have a material adverse effect on our capital expenditures and operating expenses.

From time to time, releases of materials or wastes have occurred at locations we own, owned previously 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, 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, but of which we have not been made aware, it is not possible to estimate the potential costs that may arise from unknown, latent liability risks.

Air Emissions . The federal Clean Air Act, as amended, and comparable state laws and regulations, regulate emissions of various air pollutants through the issuance of permits 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. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the Clean Air Act and associated state laws and regulations. We are required to obtain federal and state permits in connection with some activities under applicable laws. These permits impose certain conditions and restrictions on our operations, some of which require significant expenditures for compliance. Changes in these requirements, or in the permits we operate under, could increase our costs or limit operations.

Additionally, the EPA’s Tier IV regulations apply to certain off-road diesel engines used by us to power equipment in the field. Under these regulations, we are required to retrofit or retire certain engines and we are limited in the number of non-compliant off-road diesel engines we can purchase. Tier IV engines are costlier and not widely available. Until Tier IV-compliant engines that meet our needs are more widely available, these regulations could limit our ability to acquire a sufficient number of diesel engines to expand our fleet and to replace existing engines as they are taken out of service.

Other Environmental Considerations . E&P activities on federal lands may be subject to the National Environmental Policy Act, which we refer to as 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 that assesses 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. 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.

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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. Where takings of or harm to species or damages to jurisdictional streams or wetlands habitat or natural resources occur or may occur, government entities or at times private parties may act to prevent oil and natural gas exploration activities or seek damages for harm to species, habitat, or natural resources or resulting from filling of jurisdictional streams or wetlands or releases of oil, wastes, hazardous substances or other regulated materials.

The Bureau of Land Management (“BLM”) has established regulations to govern hydraulic fracturing on federal and Indian lands. In 2016, BLM published the Methane and Waste Reduction Rule to reduce waste of natural gas supplies and reduce air pollution, including greenhouse gases, for oil and natural gas produced on federal and Indian lands. Various states filed for a petition for review of the Methane and Waste Reduction Rule. On December 8, 2017, BLM published a final rule delay until January 2019 for certain requirements of the rule that had not yet gone into effect pending judicial review of the rule. A coalition of environmental groups filed suit challenging the delay. On September 28, 2018, BLM published a final rule revising the 2016 Methane and Waste Reduction Rule, which became effective on November 27, 2018. Imposition of this rules could increase our costs or limit operations.

The Toxic Substances Control Act (“TSCA”), requires manufacturers of new chemical substances to provide specific information to the Agency for review prior to manufacturing chemicals or introducing them into commerce. EPA has permitted manufacture of new chemical nanoscale materials through the use of consent orders or Significant New Use Rules under TSCA. The Agency has also allowed the manufacture of new chemical nanoscale materials under the terms of certain regulatory exemptions where exposures were controlled to protect against unreasonable risks. On May 19, 2014, the EPA published an Advanced Notice of Proposed Rulemaking to obtain data on hydraulic fracturing chemical substances and mixtures. The EPA has not yet proceeded with the rulemaking but may do so in the future. Any changes in TSCA regulations could increase our capital expenditures and operating expenses.

Climate Change . In December 2009, the EPA issued an Endangerment Finding that determined that emissions of carbon dioxide, methane and other greenhouse gases present an endangerment to public health and the environment because, according to the EPA, emissions of such gases contribute to warming of the earth’s atmosphere and other climatic changes. The EPA later adopted two sets of related rules, one of which regulates emissions of greenhouse gases from motor vehicles and the other of which regulates emissions from certain large stationary sources of emissions. The motor vehicle rule, which became effective in July 2010, limits emissions from motor vehicles. The EPA adopted the stationary source rule, which we refer to as the tailoring rule, in May 2010, and it became effective January 2011. The tailoring rule established new emissions thresholds that determine when stationary sources must obtain permits under the Prevention of Significant Deterioration (“PSD”), and Title V programs of the Clean Air Act. On June 23, 2014, in Utility Air Regulatory Group v. EPA , the Supreme Court held that stationary sources could not become subject to PSD or Title V permitting solely by reason of their greenhouse gas emissions and invalidated the tailoring rule. However, the Court ruled that the EPA may require installation of best available control technology for greenhouse gas emissions at sources otherwise subject to the PSD and Title V programs. On December 19, 2014, the EPA issued two memoranda providing guidance on greenhouse gas permitting requirements in response to the Supreme Court’s decision. In its preliminary guidance, the EPA stated that it would undertake a rulemaking action to rescind any PSD permits issued under the portions of the tailoring rule that were vacated by the Court. In the interim, the EPA issued a narrowly crafted “no action assurance” indicating it will exercise its enforcement discretion not to pursue enforcement of the terms and conditions relating to greenhouse gases in an EPA-issued PSD permit, and for related terms and conditions in a Title V permit. On April 30, 2015, the EPA issued a final rule allowing permitting authorities to rescind PSD permits issued under the invalid regulations. In October 2015, the EPA amended the greenhouse gas reporting rule to add the reporting of emissions from oil wells using hydraulic fracturing. Because of this continued regulatory focus, future emission regulations of the oil and natural gas industry remain a possibility, which could increase the cost of our operations.

In addition, the U.S. Congress occasionally attempts to adopt legislation to reduce emissions of greenhouse gases, and almost one-half of the states have taken legal measures to reduce emissions primarily through the planned development of greenhouse gas emission inventories or regional cap and trade programs. Although the U.S. Congress has not yet adopted such legislation, it may do so in the future. Several states continue to pursue related regulations as well. In December 2015, the United States joined the international community at the 21st Conference of the Parties of

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the United Nations Framework Convention on Climate Change in Paris, France. The resulting Paris Agreement calls for the parties to undertake “ambitious efforts” to limit the average global temperature, and to conserve and enhance sinks and reservoirs of greenhouse gases. The Paris Agreement, which came into force on November 4, 2016, establishes a framework for the parties to cooperate and report actions to reduce greenhouse gas emissions. Although the Trump Administration has withdrawn the United States from the Paris Agreement, many state and local officials have publicly stated they intend to abide by the terms of the Paris Agreement. Restrictions on emissions of methane or carbon dioxide that may be imposed in various states could adversely affect the oil and natural gas industry which could have a material adverse effect on future demand for our services. At this time, it is not possible to accurately estimate how potential future laws or regulations addressing greenhouse gas emissions would impact our customers’ business and consequently our own.

In addition, claims have been made against certain energy companies alleging that greenhouse gas emissions from oil and natural gas operations constitute a public nuisance under federal or state common law. As a result, private individuals may seek to enforce environmental laws and regulations and could allege personal injury or property damages, which could increase our operating costs.

NORM . In the course of our operations, some of our equipment may be exposed to naturally occurring radioactive materials (“NORM”) associated with oil and natural gas deposits and, accordingly may result in the generation of wastes and other materials containing NORM. NORM exhibiting levels of naturally occurring radiation in excess of established state standards are subject to special handling and disposal requirements, and any storage vessels, piping and work area affected by NORM may be subject to remediation or restoration requirements. Because certain of the properties presently or previously owned, operated or occupied by us may have been used for oil and natural gas production operations, it is possible that we may incur costs or liabilities associated with NORM.

Pollution Risk Management . We seek to minimize the possibility of a pollution event through equipment and job design, as well as through employee training. We also maintain a pollution risk management program if 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 exposures. This insurance portfolio has been structured in an effort to address incidents that result in bodily injury or property damage and any ensuing clean up needed at our owned facilities as a result of the mobilization and utilization of our fleet, as well as any claims resulting from our operations.

We also seek to manage environmental liability risks through provisions in our contracts with our customers that allocate risks relating to surface activities associated with the fracturing process, other than water disposal, to us and risks relating to “downhole” 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. The customers remove the water from the well using a controlled flow-back process, and 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 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 greatest 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.

Safety and Health Regulation

We are subject to the requirements of the federal Occupational Safety and Health Act, which is administered and enforced by 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

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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 new rule regarding respirable silica sand. Although it is not possible to estimate the financial and compliance impact of the new 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.

Intellectual Property Rights

Our research and development efforts are focused on providing specific solutions to the challenges our customers face when fracturing and stimulating wells. In addition to the design and manufacture of innovative equipment, we have also developed proprietary blends of chemicals that we use in connection with our hydraulic fracturing services. We have three U.S. patents and two patents in Canada relating to fracturing methods, the technology used in fluid ends, hydraulic pumps and other equipment. We believe the information regarding our customer and supplier relationships are also valuable proprietary assets. We have registered trademarks and pending trademark applications for various names under which our entities do or intend to conduct business and offer products. 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.

Company Information

Our principal executive office is located at 777 Main Street, Suite 2900, Fort Worth, Texas, 76102 and our telephone number is 817-862-2000. Our website address is www.ftsi.com. The information on our website is not incorporated by reference into this report.

Item 1A. Risk Factors

Our investors should carefully consider the following risks and other information in this annual report in evaluating us and our common stock. Any of the following risks, as well as additional risks and uncertainties not currently known to us or that we currently deem immaterial, could materially and adversely affect our business, financial condition or results of operations, and could, in turn, impact the trading price of our common stock.

Risks Relating to Our Business

Our business depends on domestic spending by the onshore oil and natural gas industry, which is cyclical and has significantly declined in past periods.

Our business is cyclical and depends on the willingness of our customers to make operating and capital expenditures to explore for, develop and produce oil and natural gas in the United States. 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, such as:

·

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;

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the level of global and domestic oil and natural gas inventories;

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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;

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·

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 E&P 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 OPEC, its members and other state-controlled oil companies relating to oil price and production controls;

·

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

·

the price and availability of alternative fuels and energy sources;

·

weather conditions and natural disasters;

·

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.

Volatility or weakness in oil and natural gas prices (or the perception that oil and natural gas prices will decrease or remain depressed) generally leads to decreased spending by our customers, which in turn negatively impacts drilling, completion and production activity. In particular, the demand for new or existing drilling, completion and production work is driven by available investment capital for such work. When these capital investments decline, our customers’ demand for our services declines. Because these types of services can be easily “started” and “stopped,” and oil and natural gas producers generally tend to be risk averse when commodity prices are low or volatile, we typically experience a more rapid decline in demand for our services compared with demand for other types of energy services. Any negative impact on the spending patterns of our customers may cause lower pricing and utilization for our services, which could have a material adverse effect on our business, financial condition, results of operations and cash flows.

Oil and natural gas prices are volatile and have declined significantly in past periods, which has adversely affected, and may again adversely affect, our financial condition, results of operations and cash flows.

The demand for our services depends on the level of spending by oil and natural gas companies for drilling, completion and production activities, which are affected by short-term and long-term trends in oil and natural gas prices, including current and anticipated oil and natural gas prices. Oil and natural gas prices, as well as the level of drilling, completion and production activities, historically have been extremely volatile and are expected to continue to be highly volatile. When oil prices have declined significantly in past periods, we have correspondingly experienced a decline in pressure pumping activity levels across our customer base during these periods. The volatile oil and natural gas prices adversely affected, and could continue to adversely affect, our financial condition, results of operations and cash flows.

Our customers may not be able to maintain or increase their reserve levels going forward.

In addition to the impact of future oil and natural gas prices on our financial performance over time, our ability to grow future revenues and increase profitability will depend largely upon our customers’ ability to find, develop or acquire additional shale oil and natural gas reserves that are economically recoverable to replace the reserves they produce. Hydraulic fractured wells are generally more short-lived than conventional wells. Our customers own or have access to a finite amount of shale oil and natural gas reserves in the United States that will be depleted over time. The production rate from shale oil and natural gas properties generally declines as reserves are depleted, while related per-unit production costs generally increase as a result of decreasing reservoir pressures and other factors. If our customers are unable to replace the shale oil reserves they own or have access to at the rate they produce such reserves, their proved reserves and production will decline over time. Reductions in production levels by our customers over time may reduce

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the future demand for our services and adversely affect our business, financial condition, results of operations and cash flows.

Our business may be adversely affected by a deterioration in general economic conditions or a weakening of the broader energy industry.

A prolonged economic slowdown or recession in the United States, adverse events relating to the energy industry or regional, national and global economic conditions and factors, particularly a slowdown in the E&P industry, could negatively impact our operations and therefore adversely affect our results. The risks associated with our business are more acute during periods of economic slowdown or recession because such periods may be accompanied by decreased exploration and development spending by our customers, decreased demand for oil and natural gas and decreased prices for oil and natural gas.

Competition in our industry intensifies during industry downturns, and we may not be able to provide services that meet the specific needs of our customers at competitive prices.

The markets in which we operate are generally highly competitive and have relatively few barriers to entry. The principal competitive factors in our markets are price, service quality, safety, and in some cases, breadth of products. We compete with large national and multi-national companies that have longer operating histories, greater financial, technical and other resources and greater name recognition than we do. Several of our competitors provide a broader array of services and have a stronger presence in more geographic markets. In addition, we compete with several smaller companies capable of competing effectively on a regional or local basis. Our competitors may be able to respond more quickly to new or emerging technologies and services and changes in customer requirements. Some contracts are awarded on a bid basis, which further increases competition based on price. Pricing is often the primary factor in determining which qualified contractor is awarded a job. The competitive environment may be further intensified by mergers and acquisitions among oil and natural gas companies or other events that have the effect of reducing the number of available customers. As a result of increased competition during the second half of 2018, we had to lower the prices for our services. In the future, we may lose market share or be unable to maintain or increase prices for our present services or to acquire additional business opportunities, which could have a material adverse effect on our business, financial condition, results of operations and cash flows.

Pressure on pricing for our services resulting from the increased competition in the second half of 2018 impacted our ability to maintain utilization and pricing for our services or implement price increases, which may also be impacted in future downturns. During any future periods of declining pricing for our services, we may not be able to reduce our costs accordingly, which could further adversely affect our results of operations. Also, we may not be able to successfully increase prices without adversely affecting our utilization levels. The inability to maintain our utilization and pricing levels, or to increase our prices as costs increase, could have a material adverse effect on our business, financial condition and results of operations.

In addition, some E&P companies have begun performing hydraulic fracturing on their wells using their own equipment and personnel. Any increase in the development and utilization of in-house fracturing capabilities by our customers could decrease the demand for our services and have a material adverse impact on our business.

We are dependent on a few customers operating in a single industry. The loss of one or more significant customers could adversely affect our financial condition and results of operations.

Our customers are engaged in the E&P business in the United States. Historically, we have been dependent upon a few customers for a significant portion of our revenues. Our four largest customers generated approximately 40%, 32%, and 52% of our total revenue in 2018, 2017 and 2016, respectively. For a discussion of our customers that make up 10% or more of our revenues, see “Business—Customers” in Item 1 of this annual report.

Our business, financial condition 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

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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 financial condition.

We extend credit to our customers, which presents a risk of nonpayment of our accounts receivable.

We extend credit to all our customers. During industry downturns in past periods, many of our customers experienced financial and operational challenges, and some of our customers filed for bankruptcy protection. Given the cyclical nature of the E&P industry, our customers may experience similar challenges in the future. As a result, we may have difficulty collecting outstanding accounts receivable from, or experience longer collection cycles with, some of our customers, which could have an adverse effect on our financial condition and cash flows.

Decreased demand for proppant has adversely affected, and could continue to adversely affect, our commitments under supply agreements.

We have purchase commitments with certain vendors to supply the proppant used in our operations. Some of these agreements have minimum purchase obligations. During industry downturns in past periods, our minimum contractual commitments have exceeded the amount of proppant needed in our operations. As a result, we made minimum payments for proppant that we were unable to use. Furthermore, some of our customers have bought and in the future may buy sand mines or proppant directly from vendors, reducing our need for proppant. If market conditions do not continue to improve, or our customers buy their own sand mines or proppant directly from vendors, we may be required to make minimum payments in future periods, which may adversely affect our results of operations, liquidity and cash flows.

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. 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. Furthermore, 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.

Our operations are subject to inherent risks, including operational hazards. These risks may not be fully covered under our insurance policies.

Our operations are subject to hazards inherent in the oil and natural gas industry, such as accidents, blowouts, explosions, craters, fires and oil spills. These hazards may lead to property damage, personal injury, death or the discharge of hazardous materials into the environment. The occurrence of a significant event or adverse claim in excess

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of the insurance coverage that we maintain or that is not covered by insurance could have a material adverse effect on our financial condition and results of operations.

As is customary in our industry, our service contracts generally provide that we will indemnify and hold harmless our customers from any claims arising from personal injury or death of our employees, damage to or loss of our equipment, and pollution emanating from our equipment and services. Similarly, our customers agree to indemnify and hold us harmless from any claims arising from personal injury or death of their employees, damage to or loss of their equipment, and pollution caused from their equipment or the well reservoir. Our indemnification arrangements may not protect us in every case. In addition, our indemnification rights may not fully protect us if the customer is insolvent or becomes bankrupt, does not maintain adequate insurance or otherwise does not possess sufficient resources to indemnify us. Furthermore, our indemnification rights may be held unenforceable in some jurisdictions. Our inability to fully realize the benefits of our contractual indemnification protections could result in significant liabilities and could adversely affect our financial condition, results of operations and cash flows.

We maintain customary insurance coverage against these types of hazards. We are self-insured up to retention limits with regard to, among other things, workers’ compensation and general liability. We maintain accruals in our consolidated balance sheets related to self-insurance retentions by using third-party data and historical claims history. The occurrence of an event not fully insured against, or the failure of an insurer to meet its insurance obligations, could result in substantial losses. In addition, we may not be able to maintain adequate insurance in the future at rates we consider reasonable. Insurance may not be available to cover any or all of the risks to which we are subject, or, even if available, it may be inadequate.

We are subject to laws and regulations regarding issues of health, safety, and protection of the environment, under which we may become liable for penalties, damages, or costs of remediation.

Our operations are subject to stringent laws and regulations relating to protection of the environment, natural resources, clean air, drinking water, wetlands, endangered species and health and safety, as well as chemical use and storage, waste management, and transportation of hazardous and non-hazardous materials. These laws and regulations subject us to risks of environmental liability, including leakage from an operator’s casing during our operations or accidental spills or releases onto or into surface or subsurface soils, surface water, groundwater or ambient air.

Some environmental laws and regulations may impose strict liability, joint and several liability or both. Strict liability means that 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 air and drinking water contamination and seismic activity, have prompted investigations that could lead to the enactment of regulations that potentially could have a material adverse impact on our business. Sanctions for noncompliance with environmental laws and regulations could result in fines and penalties (administrative, civil or criminal), revocations of permits, expenditures for remediation, and issuance of corrective action orders, and actions arising under these laws and regulations could result in liability for property damage, exposure to waste and other hazardous materials, nuisance or personal injuries. Such claims or sanctions could cause us to incur substantial costs or losses and could have a material adverse effect on our business, financial condition, and results of operations.

Changes in laws and regulations could prohibit, restrict or limit our operations, increase our operating costs, adversely affect our results or result in the disclosure of proprietary information resulting in competitive harm.

Various legislative and regulatory initiatives have been undertaken that could result in additional requirements or restrictions being imposed on our operations. Legislation and/or regulations are being considered at the federal, state and local levels that could impose chemical disclosure requirements (such as restrictions on the use of certain types of chemicals or prohibitions on hydraulic fracturing operations in certain areas) and prior approval requirements. If they become effective, these regulations would establish additional levels of regulation that could lead to operational delays and increased operating costs. Disclosure of our proprietary chemical information to third parties or to the public, even if inadvertent, could diminish the value of our trade secrets and could result in competitive harm to us, which could have an adverse impact on our financial condition and results of operations.

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Additionally, some jurisdictions 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, and are closely examining permit and disposal options for processed water, which if imposed could have a material adverse impact on our operating costs. Moreover, any moratorium or increased regulation of our raw materials vendors, such as our proppant suppliers, could increase the cost of those materials and adversely affect the results of our operations.

We are also subject to the requirements of the Occupational Safety and Health Administration’s (“OSHA”) Respirable Crystalline Silica Standard, which requires employers to limit worker exposures to respirable crystalline silica and to take other steps to protect workers, such as medical surveillance, providing employee training, and implementing a written exposure control plan. These requirements became applicable to hydraulic fracturing operations in the oil and gas industry on June 23, 2018. The rule also requires hydraulic fracturing operations in the oil and gas industry to implement engineering controls to limit exposures to the respirable silica by June 23, 2021. The Respirable Crystalline Silica Standard has and will continue to impose increased operating costs on our and our customers’ business. Employee exposure to silica presents a source of potential liability to our and our customers’ business, which if realized could increase our costs or otherwise adversely affect our business or operations.

We are also subject to various transportation regulations that include certain permit requirements of highway and vehicle and hazardous material safety authorities. These regulations govern such matters as the authorization to engage in motor carrier operations, safety, equipment testing, driver requirements and specifications and insurance requirements. As these regulations develop and any new regulations are proposed, we have experienced and may continue to experience an increase in related costs. We receive a portion of the proppant used in our operations by rail. Any delay or failure in rail services due to changes in transportation regulations, work stoppages or labor strikes, could adversely affect the availability of proppant. 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.

Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

Our business is dependent on our ability to conduct hydraulic fracturing and horizontal drilling activities. Hydraulic fracturing is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations, including shales. The process, which involves the injection of water, sand and chemicals, or proppants, under pressure into formations to fracture the surrounding rock and stimulate production, is typically regulated by state oil and natural gas commissions. However, federal agencies have asserted regulatory authority over certain aspects of the process. For example, on May 9, 2014, the EPA issued an Advanced Notice of Proposed Rulemaking seeking comment on the development of regulations under the Toxic Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing. The EPA has not proceeded further with this rulemaking but could do so in the future. On June 28, 2016, the EPA published a final rule prohibiting the discharge of wastewater from onshore unconventional oil and natural gas extraction facilities to publicly owned wastewater treatment plants. The EPA also conducted a study of private wastewater treatment facilities (also known as centralized waste treatment (“CWT”) facilities) accepting oil and natural gas extraction wastewater and in May 2018 published data and information related to the extent to which CWT facilities accept such wastewater, available treatment technologies (and their associated costs), discharge characteristics, financial characteristics of CWT facilities and the environmental impacts of discharges from CWT facilities. The EPA entered a consent decree which requires the agency to determine whether to revise the Resource Conservation and Recovery Act Subtitle D rules for oil and gas waste by March 5, 2019. Furthermore, legislation to amend the SDWA, to repeal the exemption for hydraulic fracturing (except when diesel fuels are used) from the definition of “underground injection” and require federal permitting and regulatory control of hydraulic fracturing, as well as legislative proposals to require disclosure of the chemical constituents of the fluids used in the fracturing process, were proposed in recent sessions of Congress. Additionally, BLM has established regulations imposing drilling and construction requirements for operations on federal or Indian lands including management requirements for surface operations and public disclosures of chemicals used in the hydraulic fracturing fluids. However, on December 29, 2017, BLM published a rescission of these regulations. Future imposition of these or similar regulations could cause us or our customers to incur substantial compliance costs and any failure to comply could have a material adverse effect on our financial condition or results of operations.

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On May 12, 2016, the EPA amended the New Source Performance Standards under the federal Clean Air Act to impose new standards for methane and volatile organic compounds (“VOCs”), emissions for certain new, modified, and reconstructed equipment, processes, and activities across the oil and natural gas sector. On the same day, the EPA finalized a plan to implement its minor new source review program in Indian country for oil and natural gas production, and it issued for public comment an information request that will require companies to provide extensive information instrumental for the development of regulations to reduce methane emissions from existing oil and natural gas sources. The EPA proposed changes to the New Source Performance Standards on September 11, 2018, which if finalized would streamline implementation of the rule.  The EPA is expected to publish a final revised rule in September 2019.

In November 2016, BLM promulgated regulations aimed at curbing air pollution, including greenhouse gases, for oil and natural gas produced on federal and Indian lands. Various states have filed for a petition for review of these regulations. On June 15, 2017, BLM published a Notice in the Federal Register proposing to postpone compliance dates for provisions of the rule that had not yet gone into effect pending judicial review of the rule. On October 4, 2017, the U.S. District Court for the Northern District of California invalidated BLM’s June 15, 2017 proposed postponement of compliance deadlines. On December 8, 2017, BLM promulgated a final rule delay to temporarily suspend or delay certain requirements until January 17, 2019. A coalition of environmental groups has filed suit challenging the delay. BLM finalized further revisions to its November 2016 rule on September 28, 2018. At this point, we cannot predict the final regulatory requirements or the cost to comply with such requirements with any certainty.

There are certain governmental reviews either underway or being proposed that focus on the environmental aspects of hydraulic fracturing practices. These ongoing or proposed studies, depending on their degree of pursuit and whether any meaningful results are obtained, could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory authorities. The EPA continues to evaluate the potential impacts of hydraulic fracturing on drinking water resources and the induced seismic activity from disposal wells and has recommended strategies for managing and minimizing the potential for significant injection-induced seismic events. For example, in December 2016, the EPA released its final report, entitled “Hydraulic Fracturing for Oil and Gas: Impacts from the Hydraulic Fracturing Water Cycle on Drinking Water Resources in the United States,” on the potential impacts of hydraulic fracturing on drinking water resources. The report states that the EPA found scientific evidence that hydraulic fracturing activities can impact drinking water resources under some circumstances, noting that the following hydraulic fracturing water cycle activities and local- or regional-scale factors are more likely than others to result in more frequent or more severe impacts: water withdrawals for fracturing in times or areas of low water availability; surface spills during the management of fracturing fluids, chemicals or produced water; injection of fracturing fluids into wells with inadequate mechanical integrity; injection of fracturing fluids directly into groundwater resources; discharge of inadequately treated fracturing wastewater to surface waters; and disposal or storage of fracturing wastewater in unlined pits. Other governmental agencies, including the U.S. Department of Energy, the U.S. Geological Survey and the U.S. Government Accountability Office, have evaluated or are evaluating various other aspects of hydraulic fracturing. These ongoing or proposed studies could spur initiatives to further regulate hydraulic fracturing, and could ultimately make it more difficult or costly to perform fracturing and increase the costs of compliance and doing business for our customers. Furthermore, the EPA plans to continue an enforcement initiative to ensure energy extraction activities comply with federal laws.

In addition to bans on hydraulic fracturing activities in Maryland, New York and Vermont, several states, including Texas and Ohio, as well as regional authorities like the Delaware River Basin Commission, have adopted or are considering adopting regulations that could restrict or prohibit hydraulic fracturing in certain circumstances, impose more stringent operating standards and/or require the disclosure of the composition of hydraulic fracturing fluids. Any increased regulation of hydraulic fracturing, in these or other states, could reduce the demand for our services and materially and adversely affect our revenues and results of operations.

There has been increasing public controversy regarding hydraulic fracturing with regard to the use of fracturing fluids, induced seismic activity, impacts on drinking water supplies, use of water and the potential for impacts to surface water, groundwater and the environment generally. A number of lawsuits and enforcement actions have been initiated across the country implicating hydraulic fracturing practices. If new laws or regulations are adopted that significantly restrict hydraulic fracturing, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations as well as make it easier for third parties opposing the hydraulic fracturing process to

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initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. In addition, if hydraulic fracturing is further regulated at the federal, state or local level, our customers’ fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements and also to attendant permitting delays and potential increases in costs. Such legislative or regulatory changes could cause us or our customers to incur substantial compliance costs, and compliance or the consequences of any failure to comply by us could have a material adverse effect on our financial condition and results of operations. At this time, it is not possible to estimate the impact on our business of newly enacted or potential federal, state or local laws governing hydraulic fracturing.

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, 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. Local, state, and federal 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 or other gases that could have a material adverse effect on our business, results of operations, and financial condition.

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 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 financial condition, prospects and results of operations.

Restrictions on drilling activities intended to protect certain species of wildlife may adversely affect our ability to conduct drilling activities in some of the areas where we operate.

Oil and natural gas operations in our operating areas can be adversely affected by seasonal or permanent restrictions on drilling activities designed to protect various wildlife, which may limit our ability to operate in protected

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areas. Permanent restrictions imposed to protect endangered species could prohibit drilling in certain areas or require the implementation of expensive mitigation measures. Additionally, the designation of previously unprotected species as threatened or endangered in areas where we operate could result in increased costs arising from species protection measures. Restrictions on oil and natural gas operations to protect wildlife could reduce demand for our services.

Conservation measures and technological advances could reduce demand for oil and natural gas and our services.

Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas, technological advances in fuel economy and energy generation devices could reduce demand for oil and natural gas, resulting in reduced demand for oilfield services. The impact of the changing demand for oil and natural gas services and products may have a material adverse effect on our business, financial condition, results of operations and cash flows.

There may be a reduction in demand for our future services due to competition from alternative energy sources.

Oil and natural gas competes with other sources of energy for consumer demand. There are significant governmental incentives and consumer pressures to increase the use of alternative energy sources in the United States and abroad. A number of automotive, industrial and power generation manufacturers are developing more fuel efficient engines, hybrid engines and alternative clean power systems using fuel cells or clean burning fuels. Greater use of these alternatives as a result of governmental incentives or regulations, technological advances, consumer demand, improved pricing or otherwise over time will reduce the demand for our products and services and adversely affect our business, financial condition, results of operations and cash flows going forward.

Limitations on construction of new natural gas pipelines or increases in federal or state regulation of natural gas pipelines could decrease demand for our services.

There has been increasing public controversy regarding construction of new natural gas pipelines and the stringency of current regulation of natural gas pipelines. Delays in construction of new pipelines or increased stringency of regulation of existing natural gas pipelines at either the state or federal level could reduce the demand for our services and materially and adversely affect our revenues and results of operations.

Our existing fleets require significant amounts of capital for maintenance, upgrades and refurbishment and any new fleets we build or acquire may require significant capital expenditures.

Our fleets require significant capital investment in maintenance, upgrades and refurbishment to maintain their effectiveness. While we manufacture many of the components necessary to maintain, upgrade and refurbish our fleets, labor costs have increased in the past and may increase in the future with increases in demand, which will require us to incur additional costs to upgrade any of our existing fleets or build any new fleets.

Additionally, competition or advances in technology within our industry may require us to update or replace existing fleets or build or acquire new fleets. Such demands on our capital or reductions in demand for our existing fleets and the increase in cost of labor necessary for such maintenance and improvement, in each case, could have a material adverse effect on our business, financial condition, results of operations and cash flows.

Our operations require substantial capital and we may be unable to obtain needed capital or financing on satisfactory terms or at all, which could limit our ability to grow.

The oilfield services industry is capital intensive. In conducting our business and operations, we have made, and expect to continue to make, substantial capital expenditures. Our total capital expenditures were $100.5 million, $64.0 million and $10.3 million, respectively, in 2018, 2017 and 2016. Since 2015, we have financed capital expenditures primarily with funding from cash on hand. We may be unable to generate sufficient cash from operations and other capital resources to maintain planned or future levels of capital expenditures which, among other things, may prevent us

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from properly maintaining our existing equipment or acquiring new equipment. Furthermore, any disruptions or continuing volatility in the global financial markets may lead to an increase in interest rates or a contraction in credit availability impacting our ability to finance our operations. This circumstance could put us at a competitive disadvantage or interfere with our growth plans. Furthermore, our actual capital expenditures for future years could exceed our capital expenditure budgets. In the event our capital expenditure requirements at any time are greater than the amount we have available, we could be required to seek additional sources of capital, which may include debt financing, joint venture partnerships, sales of assets, offerings of debt or equity securities or other means. We may not be able to obtain any such alternative source of capital. We may be required to curtail or eliminate contemplated activities. If we can obtain alternative sources of capital, the terms of such alternative may not be favorable to us. In particular, the terms of any debt financing may include covenants that significantly restrict our operations. Our inability to grow as planned may reduce our chances of maintaining and improving profitability.

A third party may claim we infringed upon its intellectual property rights, and we may be subjected to costly litigation.

Our operations, including equipment, manufacturing and fluid and chemical operations may unintentionally infringe upon the patents or trade secrets of a competitor or other company that uses proprietary components or processes in its operations, and that company may have legal recourse against our use of its protected information. If this were to happen, these claims could result in legal and other costs associated with litigation. If found to have infringed upon protected information, we may have to pay damages or make royalty payments in order to continue using that information, which could substantially increase the costs previously associated with certain products or services, or we may have to discontinue use of the information or product altogether. Any of these could materially and adversely affect our business, financial condition or results of operations.

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. Furthermore, we may face competitive pressure to 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 implement new technologies before we can. We cannot be certain that we will be able to implement all new technologies or products on a timely basis or at an acceptable cost. Thus, limits on our ability to effectively use and implement new and emerging technologies may have a material adverse effect on our business, financial condition or results of operations.

Loss or corruption of our information or a cyberattack on our computer systems could adversely affect our business.

We are heavily dependent on our information systems and computer-based programs, including our well operations information and accounting data. If any of such programs or systems were to fail or create erroneous information in our hardware or software network infrastructure, whether due to cyberattack or otherwise, possible consequences include our loss of communication links and inability to automatically process commercial transactions or engage in similar automated or computerized business activities. Any such consequence could have a material adverse effect on our business.

The oil and natural gas industry has become increasingly dependent on digital technologies to conduct certain activities. At the same time, cyberattacks have increased. The U.S. government has issued public warnings that indicate that energy assets might be specific targets of cyber security threats. Our technologies, systems and networks may become the target of cyberattacks or information security breaches. These could result in the unauthorized access, misuse, loss or destruction of our proprietary and other information or other disruption of our business operations. Any access or surveillance could remain undetected for an extended period. Our systems for protecting against cyber security risks may not be sufficient. As cyber incidents continue to evolve, we may be required to expend additional resources to

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continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyber incidents. Additionally, our insurance coverage for cyberattacks may not be sufficient to cover all the losses we may experience as a result of such cyberattacks. Any additional costs could materially adversely affect our results of operations.

One or more of our directors may not reside in the United States, which may prevent investors from obtaining or enforcing judgments against them.

Because one or more of our directors may not reside in the United States, it may not be possible for investors to effect service of process within the United States on our non-U.S. resident directors, enforce judgments obtained in U.S. courts based on the civil liability provisions of the U.S. federal securities laws against our non-U.S. resident directors, enforce in foreign courts U.S. court judgments based on civil liability provisions of the U.S. federal securities laws against our non-U.S. resident directors, or bring an original action in foreign courts to enforce liabilities based on the U.S. federal securities laws against our non-U.S. resident directors.

Adverse weather conditions could impact demand for our services or impact our costs.

Our business could be 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 or unusually cold winters could adversely affect our capability to perform our services, for example, due to delays in the delivery of equipment, personnel and products that we need in order to provide our services and weather-related damage to facilities and equipment, resulting in delays in operations. Our operations in arid regions can be affected by droughts and limited access to water used in our hydraulic fracturing operations. These constraints could adversely affect the costs and results of operations.

A terrorist attack or armed conflict could harm our business.

Terrorist activities, anti-terrorist efforts and other armed conflicts involving the United States could adversely affect the U.S. and global economies and could prevent us from meeting financial and other obligations. We could experience loss of business, delays or defaults in payments from payors or disruptions of fuel supplies and markets if wells, operations sites or other related facilities are direct targets or indirect casualties of an act of terror or war. Such activities could reduce the overall demand for oil and natural gas, which, in turn, could also reduce the demand for our products and services. Terrorist activities and the threat of potential terrorist activities and any resulting economic downturn could adversely affect our results of operations, impair our ability to raise capital or otherwise adversely impact our ability to realize certain business strategies.

International operations subject us to additional economic, political and regulatory risks.

We have a joint venture with Sinopec to provide hydraulic fracturing operations in China. International operations require significant resources and may result in foreign operations that ultimately are not successful. Our joint venture operations expose us to operational risks, including exposure to foreign currency rate fluctuations, war or political instability, limitations on the movement of funds, foreign and domestic government regulation, including compliance with the U.S. Foreign Corrupt Practices Act, trade wars, and bureaucratic delays. These may increase our costs and distract key personnel, which may adversely affect our business, financial condition or results of operations.

We and certain of our directors, executive officers and stockholders are currently subject to securities class action litigation in connection with our IPO, and other litigation and legal proceeding (including arbitration) that are expensive and time consuming, and if resolved adversely, could harm our business, financial condition or results or operation.

A purported securities class action was filed against us and certain of our directors, executive officers and stockholders alleging violation of federal securities laws. While we believe this lawsuit is without merit and intend to vigorously defend against it, there can be no assurances that a favorable final outcome will be obtained. In connection with this litigation, we could incur substantial costs and such costs and any related settlements or judgments may not be

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covered by insurance. We could also suffer an adverse impact on our reputation and a diversion of management’s attention and resources, which could have a material adverse effect on our business.

In addition to the class action lawsuit, we are involved in other lawsuits and legal proceedings, including arbitration, in the ordinary course of our business. Any litigation or other legal proceedings, including arbitration, could result in an onerous or unfavorable judgment that may not be reversed upon appeal or in payments of substantial monetary damages or fines, or we may decide to settle lawsuits on similarly unfavorable terms, either of which could adversely affect our business, financial conditions, or results of operation.

Our ability to utilize our net operating loss carryforwards and certain tax amortization deductions may be delayed or limited.

As of December 31, 2018, we had federal and state net operating loss carryforwards (“NOLs”) in excess of $1,500 million, which if not utilized will begin to expire starting in 2032 for federal purposes and 2019 for state purposes. We may use these NOLs to offset against taxable income for U.S. federal and state income tax purposes. Additionally, we are allowed to deduct approximately $190 million of amortization expense on our federal and state tax returns per year for tax years 2019 through 2025. However, Section 382 of the Internal Revenue Code of 1986, as amended, may reduce the amount of the NOLs we may use or tax amortization we may deduct for U.S. federal income tax purposes in the event of certain changes in ownership of our Company. A Section 382 “ownership change” generally occurs if one or more stockholders or groups of stockholders who own at least 5% of a company’s stock (with owners holding less than 5% of the company’s stock being consolidated together into one or more “public groups”) increase their ownership by more than 50 percentage points over their lowest ownership percentage within a rolling three year period—for example, if we and/or our three largest stockholders were to sell shares of our common stock, so that following such sales, the “public group” owned more than 50% of our common stock, an “ownership change” would occur for purposes of Code Section 382. Similar rules may apply under state tax laws. Future issuances or sales of our stock, including by our large stockholders or certain other transactions involving our stock that are outside of our control, could cause an “ownership change.” If an “ownership change” has occurred in the past or occurs in the future, Section 382 would impose an annual limit on the amount of pre-ownership change NOLs and other tax attributes, potentially including a portion of our tax amortization deduction, that we can use to reduce our taxable income each year, potentially increasing and accelerating our liability for income taxes, and also potentially causing those tax attributes to expire unused. Any limitation of our tax amortization deduction or use of NOLs could, depending on the extent of such limitation and the amount of NOLs previously used, result in our retaining less cash after payment of U.S. federal and state income taxes during any year in which we have taxable income, rather than losses, than we would be entitled to retain if such NOLs or tax amortization deductions were not reduced as an offset against such income for U.S. federal and state income tax reporting purposes, which could adversely impact our operating results.

Risks Relating to Our Indebtedness

We have substantial indebtedness. Any failure to meet our debt obligations would adversely affect our liquidity and financial condition.

As of December 31, 2018, we had $507.9 million of long-term indebtedness outstanding. Our indebtedness affects our operations in several ways, including the following:

·

a portion of our cash flows from operating activities must be used to service our indebtedness and is not available for other purposes;

·

the covenants contained in the debt agreements governing our outstanding indebtedness limit our ability to borrow additional funds, and may also affect our flexibility in planning for, and reacting to, changes in the economy and in our industry; and

·

a lowering of the credit ratings of our debt may negatively affect the cost, terms, conditions and availability of future financing.

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If our cash flow and other capital resources are insufficient to fund our obligations under our debt agreements on a current basis and at maturity, or if we are otherwise unable to comply with the covenants in those agreements, we will need to refinance or restructure our debt. The proceeds of future borrowings may not be sufficient to refinance or repay the debt, and we may be unable to complete such transactions in a timely manner, on favorable terms, or at all. In addition, if we finance our operations through additional indebtedness, then the risks that we now face relating to our current debt level would intensify, and it would be more difficult to satisfy our existing financial obligations. Furthermore, if a default occurs under one debt agreement, then this could cause a cross-default under other debt agreements.

Liquidity is essential to our business, and it has been and may continue to be adversely affected.

Liquidity is essential to our business to service our debt and purchase the labor, materials and equipment that we use to operate our business. Additionally, we believe that a service provider’s liquidity is important to our customers because adequate liquidity provides assurance that a service provider will have the financial resources to continue to operate in challenging industry conditions.

Our liquidity has been adversely affected by industry downturns in past periods due to low or non-existent profit margins for utilization of our services. Our liquidity may be further impaired by unforeseen cash expenditures, which may arise due to circumstances beyond our control.

Additionally, the terms of our existing debt instruments restrict, and any future debt instruments may further restrict, our ability to incur additional indebtedness, sell certain assets and engage in certain business activities. These restrictions prohibit activities that we could use to increase our liquidity. Also, our current lenders and investors hold a first lien on a portion of our assets as collateral, including substantially all of our revenue-generating equipment. New lenders and investors may require additional collateral, which could additionally impair our access to liquidity. If alternate financing is not available on favorable terms or at all, we would be required to decrease our capital spending to an even greater extent. Any additional decrease in our capital spending would adversely affect our ability to sustain or improve our profits. Refinancing may not be available, and any refinancing of our debt could be at higher interest rates, which could further adversely affect our liquidity.

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 our term loan due April 16, 2021 (the “Term Loan”) and our asset based lending facility under the Credit Agreement entered into February 22, 2018 (the “Credit Facility”) and to the extent we raise additional debt in the capital markets at variable rates, including any future revolving credit facility, to meet maturing debt obligations or to fund our capital expenditures and working capital needs. Daily working capital requirements are typically financed with operational cash flow and through the use of our existing borrowings. The interest rate on the Term Loan and Credit Facility is generally determined from the applicable LIBOR rate at the borrowing date plus a pre-set margin. We are therefore subject to market interest rate risk on that portion of our long-term debt that relates to the Term Loan and Credit Facility. We do not employ risk management techniques, such as interest rate swaps, to hedge against interest rate volatility, and accordingly significant and sustained increases in market interest rates could materially increase our financing costs and negatively impact our reported results.

Risks Relating to Our Common Stock

Our three largest stockholders control a significant percentage of our common stock, and their interests may conflict with those of our other stockholders.

Before our initial public offering (the “IPO”) in February 2018, we were controlled by an investor group comprised mainly of Maju Investments (Mauritius) Pte Ltd (“Maju”), an indirect wholly owned subsidiary of Temasek Holdings (Private) Limited (“Temasek”), CHK Energy Holdings, Inc. (“Chesapeake”), a wholly owned subsidiary of Chesapeake Energy Corporation (“Chesapeake Parent”), and Senja Capital Ltd (“Senja”), an investment company affiliated with RRJ Capital Limited (“RRJ”). Maju, Chesapeake and Senja beneficially own approximately 37.9%, 20.0% and 10.8%, respectively, of our common stock. As a result, Maju, Chesapeake and Senja, together, exercise

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significant influence over matters requiring stockholder approval, including the election of directors, changes to our organizational documents and significant corporate transactions. Furthermore, several individuals who serve as our directors are nominees of Maju, Chesapeake and Senja. This concentration of ownership and relationships with Maju, Chesapeake and Senja make it unlikely that any other holder or group of holders of our common stock will be able to affect the way we are managed or the direction of our business. In addition, we have engaged, and expect to continue to engage, in related party transactions involving Chesapeake. Furthermore, we have entered into investors’ rights agreements with Maju, Chesapeake, Senja and Hampton Asset Holding Ltd. (“Hampton”), which contain agreements regarding, among other things, director nomination, information and observer rights. The interests of Maju, Chesapeake and Senja with respect to matters potentially or actually involving or affecting us, such as future acquisitions and financings, may conflict with the interests of our other stockholders. This continued concentrated ownership will make it more difficult for another company to acquire us and for our investors to receive any related takeover premium for their shares unless these stockholders approve the acquisition.

A significant reduction by our major stockholders of their ownership interests in us could adversely affect us.

We believe that the substantial ownership interests of Maju, Chesapeake and Senja in us provides them with an economic incentive to assist us to be successful. If Maju, Chesapeake or Senja sell all or a substantial portion of their ownership interest in us, they may have less incentive to assist in our success and their nominees that serve as members of our board of directors may resign. Such actions could adversely affect our ability to successfully implement our business strategies which could adversely affect our cash flows or results of operations. In addition, such actions may prohibit us from utilizing all or a portion of our net operating loss carryforwards. See “—Risks Related to our Business—Our ability to use our net operating loss carryforwards may be limited.”

Our stock price may be volatile.

The market price of our common stock could vary significantly as a result of a number of factors, some of which are beyond our control. In the event of a drop in the market price of our common stock, our investors could lose a substantial part or all of their investment in our common stock. Consequently, our investors may not be able to sell shares of our common stock at prices equal to or greater than the price they paid.

The following factors, among others, could affect our stock price:

·

our operating and financial performance;

·

quarterly variations in the rate of growth of our financial indicators, such as net income per share, net income and revenues;

·

actual or anticipated changes in revenue or earnings estimates or publication of reports by equity research analysts;

·

speculation in the press or investment community or the dissemination of information through social media platforms;

·

sales of our common stock by us or our stockholders, or the perception that such sales may occur;

·

litigation involving us or that may be perceived as having an adverse effect on our business;

·

general market conditions, including fluctuations in actual and anticipated future commodity prices;

·

errors in our forecasting of the demand for our services, which could lead to lower revenue or increased costs; and

·

domestic and international economic, legal and regulatory factors unrelated to our performance.

The stock markets in general have experienced extreme volatility that has often been unrelated to the operating performance of particular companies. These broad market fluctuations may adversely affect the trading price of our common stock.

25


 

The requirements of being a public company, including compliance with the reporting requirements of the Securities Exchange Act of 1934, as amended ( the “Exchange Act”) and the requirements of the Sarbanes-Oxley Act of 2002 ( the “Sarbanes-Oxley Act”) and the Dodd-Frank Act, may increase our costs. We may be unable to comply with these requirements in a timely or cost-effective manner.

As a public company with listed equity securities, we have to comply with numerous laws, regulations and requirements, certain corporate governance provisions of the Sarbanes-Oxley Act, the Dodd-Frank Wall Street Reform and Consumer Protection Act, related regulations of the U.S. Securities and Exchange Commission (the “SEC”) and the requirements of the national stock exchange on which our common stock is listed, with which we were not required to comply as a private company. Complying with these statutes, regulations and requirements will require time and attention from our board of directors and management and will increase our costs and expenses. We will need to:

·

institute a more comprehensive compliance function;

·

expand, evaluate and maintain our system of internal controls over financial reporting in compliance with the requirements of Section 404 of the Sarbanes-Oxley Act and the related rules and regulations of the SEC and the Public Company Accounting Oversight Board (United States);

·

maintain internal policies, such as those relating to disclosure controls and procedures and insider trading;

·

comply with corporate governance and other rules promulgated by the national stock exchange on which our common stock is listed;

·

prepare and file annual, quarterly and other periodic public reports in compliance with the federal securities laws;

·

prepare proxy statements and solicit proxies in connection with annual meetings of our stockholders;

·

involve and retain to a greater degree outside counsel and accountants in the above activities; and

·

maintain a public company investor relations function.

In addition, being a public company subject to these rules and regulations required us to obtain increased director and officer liability insurance coverage and we incurred substantial costs to obtain such coverage. These factors could also make it more difficult for us to attract and retain qualified members of our board of directors, particularly to serve on our audit committee, and qualified executive officers.

Anti-takeover provisions in our charter documents and under Delaware law could make an acquisition of us more difficult, limit attempts by our stockholders to replace or remove our current management and limit the market price of our common stock.

Provisions in our amended and restated certificate of incorporation and amended and restated bylaws may have the effect of delaying or preventing a change of control or changes in our management. Our amended and restated certificate of incorporation and amended and restated bylaws:

·

provide that our board of directors is classified into three classes of directors;

·

provide that stockholders may, except as set forth in the investors’ rights agreements, which we entered into with Maju, Chesapeake, Senja and Hampton, remove directors only for cause and only with the approval of holders of at least 662/3% of our then-outstanding capital stock;

·

provide that the authorized number of directors may be changed only by resolution of the board of directors;

·

provide that all vacancies, including newly created directorships, may be filled by the affirmative vote of a majority of directors then in office, even if less than a quorum, except, at any time Maju, Chesapeake, Senja and Hampton have the right to nominate a director under their respective investors’ rights agreement,

26


 

any vacancy resulting from the death, disability, retirement, resignation, or removal, of a director nominated by these stockholders will be filled by the applicable nominating stockholder;

·

provide that our stockholders may not take action by written consent, and may only take action at annual or special meetings of our stockholders;

·

provide that stockholders, other than Maju, Chesapeake, Senja and Hampton, seeking to present proposals before a meeting of stockholders or to nominate candidates for election as directors at a meeting of stockholders must provide notice in writing in a timely manner, and also specify requirements as to the form and content of a stockholder’s notice;

·

restrict the forum for certain litigation against us to Delaware;

·

not provide for cumulative voting rights (therefore allowing the holders of a majority of the shares of common stock entitled to vote in any election of directors to elect all of the directors standing for election);

·

provide that special meetings of our stockholders may be called only by (1) the Chairman of the board of directors, (2) our CEO, (3) the board of directors pursuant to a resolution adopted by a majority of the total number of authorized directors or (4) stockholders with at least 25% of our then-outstanding capital stock;

·

provide that, except as set forth in the investors’ rights agreements, stockholders will be permitted to amend our amended and restated bylaws only upon receiving at least 662/3% of the votes entitled to be cast by holders of all outstanding shares then entitled to vote generally in the election of directors, voting together as a single class; and

·

provide that, except as set forth in the investors’ rights agreements, certain provisions of our amended and restated certificate of incorporation may only be amended upon receiving at least 662/3% of the votes entitled to be cast by holders of all outstanding shares then entitled to vote, voting together as a single class.

These provisions may frustrate or prevent any attempts by our stockholders to replace or remove our current management by making it more difficult for stockholders to replace members of our board of directors, which is responsible for appointing the members of our management. In addition, we will opt out of the provisions of Section 203 of the General Corporation Law of the State of Delaware (“DGCL”), which generally prohibits a Delaware corporation from engaging in any of a broad range of business combinations with any “interested” stockholder for a period of three years following the date on which the stockholder became an “interested” stockholder. However, our amended and restated certificate of incorporation provides substantially the same limitations as are set forth in Section 203 but also provides that Maju and Chesapeake and their affiliates and any of their direct or indirect transferees and any group as to which such persons are a party do not constitute “interested stockholders” for purposes of this provision.

We are subject to certain requirements of Section 404 of the Sarbanes-Oxley Act. If we are unable to timely comply with Section 404 or if the costs related to compliance are significant, our profitability, stock price, results of operations and financial condition could be materially adversely affected.

We are required to comply with certain provisions of Section 404 of the Sarbanes-Oxley Act of 2002. Section 404 requires that we document and test our internal control over financial reporting and issue management’s assessment of our internal control over financial reporting. This section also requires that our independent registered public accounting firm opine on those internal controls upon becoming an accelerated filer, as defined in the SEC rules. During the course of our ongoing evaluation, we may identify areas requiring improvement, and we may have to design enhanced processes and controls to address issues identified through this review. For example, we anticipate the need to hire, or contract with, additional administrative and accounting personnel to enable us to comply with these provisions while maintaining sound financial reporting practices. We believe that the out-of-pocket costs, the diversion of management’s attention from running the day-to-day operations and operational changes caused by the need to comply with the requirements of Section 404 of the Sarbanes-Oxley Act could be significant. If the time and costs associated with such compliance exceed our current expectations and our results of operations could be adversely affected.

We cannot be certain at this time that we will be able to successfully complete the attestation requirements of Section 404 or that we or our auditors will not identify material weaknesses in internal control over financial reporting.

27


 

If we fail to comply with the requirements of Section 404 or if we or our auditors identify and report such material weaknesses, the accuracy and timeliness of the filing of our annual and quarterly reports may be materially adversely affected and could cause investors to lose confidence in our reported financial information, which could have a negative effect on the trading price of our common stock. In addition, a material weakness in the effectiveness of our internal control over financial reporting could result in an increased chance of fraud and the loss of customers, reduce our ability to obtain financing and require additional expenditures to comply with these requirements, each of which could have a material adverse effect on our business, results of operations and financial condition.

We may not pay dividends on our common stock and, consequently, investors would achieve a return on investment only if the price of our stock appreciates.

We may not declare dividends on shares of our common stock. Additionally, we are currently limited in our ability to make cash distributions to stockholders or repurchase shares of our common stock pursuant to the terms of our Term Loan, Credit Facility and the indenture governing our 6.250% senior secured notes due May 1, 2022 (the “2022 Notes”). If we do not make cash distributions to stockholders or otherwise return cash to stockholders, a return on investment in us will only be achieved if the market price of our common stock appreciates, which may not occur, and our investors sell their shares at a profit. There is no guarantee that the price of our common stock in the market will exceed the price that our investors pay.

Future sales of our common stock in the public market could lower our stock price, and any additional capital raised by us through the sale of equity or convertible securities may dilute our investors’ ownership in us.

We may sell additional shares of common stock in subsequent public offerings and may also issue securities convertible into our common stock. On February 6, 2018, we registered shares of common stock that we have granted as equity awards or may grant as equity awards under the FTS International, Inc. 2018 Equity and Incentive Compensation Plan (the “2018 Plan”). These shares may be sold freely in the public market, subject to volume limitations applicable to affiliates, applicable vesting periods and lock-up agreements.

We cannot predict the size of future issuances of our common stock or the effect, if any, that future issuances and sales of shares of our common stock will have on the market price of our common stock. Sales of substantial amounts of our common stock (including shares issued in connection with an acquisition), or the perception that such sales could occur, may adversely affect prevailing market prices of our common stock.

If securities analysts do not publish research or reports about our business, publish inaccurate or unfavorable research or if they downgrade our stock or our sector, our common stock price and trading volume could decline.

The trading market for our common stock relies in part on the research and reports that industry or financial analysts publish about us or our business. We do not control these analysts. Furthermore, if one or more of the analysts who do cover us downgrade our stock or our industry, or the stock of any of our competitors, or publish inaccurate or unfavorable research about our business, the price of our stock could decline. If one or more of these analysts ceases coverage of us or fail to publish reports on us regularly, we could lose visibility in the market, which in turn could cause our stock price or trading volume to decline.

We may issue preferred stock whose terms could adversely affect the voting power or value of our common stock.

Our amended and restated certificate of incorporation authorizes us to issue, without the approval of our stockholders, one or more classes or series of preferred stock having such designations, preferences, limitations and relative rights, including preferences over our common stock respecting dividends and distributions, as our board of directors may determine. The terms of one or more classes or series of preferred stock could adversely impact the voting power or value of our common stock. For example, we might grant holders of preferred stock the right to elect some number of our directors in all events or on the happening of specified events or the right to veto specified transactions.

28


 

Similarly, the repurchase or redemption rights or liquidation preferences we might assign to holders of preferred stock could affect the residual value of our common stock.

Item 1B. Unresolved Staff Comments

None.

Item 2. Properties

Our principal properties include our district offices and manufacturing facilities. We believe our facilities are in good condition and suitable for the purposes for which they are used. Below is information detailing our properties as of December 31, 2018.

Hydraulic Fracturing District Offices

Currently, we have five district offices out of which we conduct hydraulic fracturing services. We own the land and facilities at each of these locations. The following table provides certain information about our district offices out of which we conduct hydraulic fracturing services office locations as of December 31, 2018.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Facilities

 

 

 

 

 

 

Size (Sq.Ft.)

 

Acres

District Office

  

Primary Area of Service

  

Formation

  

(approx.)

  

(approx.)

Odessa, Texas

 

Southeast New Mexico and West Texas

 

Permian Basin

 

82,800

 

36

Elk City, Oklahoma

 

Oklahoma

 

SCOOP/STACK

 

42,330

 

40

Washington County, Pennsylvania

 

Pennsylvania, West Virginia and Ohio

 

Marcellus/Utica Shale

 

41,660

 

27

Pleasanton, Texas

 

South Texas

 

Eagle Ford Shale

 

62,950

 

113

Longview, Texas

 

East Texas and West Louisiana

 

Haynesville Shale

 

36,000

 

14

 

We also lease a 22-acre, 250,000 square foot facility in Williamsport, Pennsylvania that we used as a district office until August 2015. We are actively seeking to sublease this facility. We may also reopen this facility if we determine it is needed for operations in the region in the future.

Wireline District Offices

Currently, we conduct wireline services out of our Odessa, Texas district office, our Longview, Texas district office, and two other locations listed in the table below. Unless otherwise noted, we own the land and facilities at each of the locations included in the table below. The following table provides certain information about our district offices out of which we conduct wireline services as of December 31, 2018.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Facilities

 

 

 

 

 

 

Size (Sq. Ft.)

 

Acres

District Office

  

Primary Area of Service

  

Formation

  

(approx.)

  

(approx.)

Yukon, Oklahoma(1)

 

Oklahoma

 

SCOOP/STACK

 

10,950

 

10

Pleasanton, Texas

 

South Texas

 

Eagle Ford Shale

 

14,375

 

14


(1)

Leased Facility

 

Manufacturing and Maintenance Facilities

We manufacture the proprietary, high-pressure pumps, including the fluid-ends and power-ends, as well as certain other equipment that we use in our hydraulic fracturing operations in an 89,522 square foot facility owned by us in Fort Worth, Texas.

29


 

We own a 94,050 square foot facility in Aledo, Texas that is used for equipment repair, maintenance and electronics installation. We also manufacture, refurbish and assemble certain components of our hydraulic fracturing units and other service equipment at this facility.

We also own a 55,000 square foot maintenance facility in Shreveport, Louisiana and lease a 12,000 square foot maintenance facility in Hobbs, New Mexico.

Principal Executive Offices

We maintain principal executive offices in Fort Worth, Texas. As of December 31, 2018 we leased approximately 33,000 square feet.

Sales Offices

We have five sales offices, which we lease in Houston and Midland, Texas, Oklahoma City, Oklahoma, Canonsburg, Pennsylvania, and Denver, Colorado.

Item 3. Legal Proceedings

We are involved in various legal proceedings from time to time in the ordinary course of our business. For additional information regarding our legal proceedings, see Note 12 — “Commitments and Contingencies” in Notes to our Consolidated Financial Statements included elsewhere in this annual report.

Item 4. Mine Safety Disclosures

Not applicable.

PART II

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

Stockholder Information

On February 22, 2019, we had 109,794,386 shares of common stock outstanding held by a total of approximately 30 record holders. The number of record holders is based on the records of American Stock Transfer & Trust Company, LLC, who serves as our transfer agent. The number of holders does not include individuals or entities who beneficially own shares but whose shares are held of record by a broker or clearing agency, but does include each such broker or clearing agency as one record holder.

Market Information

Our common stock trades on the New York Stock Exchange (the “NYSE”) under the ticker symbol “FTSI.”

Dividends

We have not paid any cash dividends on our common stock in the past two fiscal years. We currently intend to retain the majority of future earnings, if any, for use in the repayment of our existing indebtedness and in the operation and expansion of our business. Therefore, we may not pay any cash dividends. The declaration and payment of future cash dividends will be at the sole discretion of our board of directors, subject to applicable laws.

30


 

Corporate Performance Graph

The following graph shows a comparison from February 2, 2018 (the date our common stock commenced trading on the NYSE) through December 31, 2018, of the cumulative total return for our common stock, the Philadelphia Oil Service Index (OSX), and the Standard & Poor’s 400 MidCap Stock Index. This comparison assumes the investment of $100 on February 2, 2018, and the reinvestment of all dividends. The shareholder return of the following graph is not necessarily indicative of future stock price performance.

PICTURE 7

 

31


 

Item 6. Selected Financial Data

You should read this information together with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our consolidated financial statements and related notes included elsewhere in this annual report on Form 10-K.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Year Ended December 31,

(Dollars in millions, except per share amounts)

  

2018

  

2017

  

2016

  

2015

  

2014

Statements of Operations Data:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Revenue

 

$

1,543.3

 

$

1,466.1

 

$

532.2

 

$

1,375.3

 

$

2,368.4

Costs of revenue, excluding depreciation,
depletion, and amortization

 

 

1,033.2

 

 

1,009.8

 

 

510.5

 

 

1,257.9

 

 

1,804.9

Selling, general and administrative

 

 

87.9

 

 

81.0

 

 

64.4

 

 

154.7

 

 

206.3

Depreciation and amortization

 

 

84.7

 

 

86.6

 

 

112.6

 

 

272.4

 

 

294.4

Impairments and other charges (1)

 

 

19.2

 

 

1.8

 

 

12.3

 

 

619.9

 

 

9.8

(Gain) loss on disposal of assets, net

 

 

(0.1)

 

 

(1.4)

 

 

1.0

 

 

5.9

 

 

5.8

Gain on insurance recoveries

 

 

 —

 

 

(2.9)

 

 

(15.1)

 

 

 —

 

 

 —

Operating income (loss)

 

 

318.4

 

 

291.2

 

 

(153.5)

 

 

(935.5)

 

 

47.2

Interest expense, net

 

 

49.3

 

 

86.7

 

 

87.5

 

 

77.2

 

 

74.2

Loss (gain) on extinguishment of debt, net

 

 

9.8

 

 

1.4

 

 

(53.7)

 

 

0.6

 

 

28.4

Equity in net (income) loss of joint venture affiliate

 

 

(1.1)

 

 

0.8

 

 

2.8

 

 

1.4

 

 

 —

Income (loss) before income taxes

 

 

260.4

 

 

202.3

 

 

(190.1)

 

 

(1,014.7)

 

 

(55.4)

Income tax expense (benefit) (2)

 

 

2.0

 

 

1.6

 

 

(1.6)

 

 

(1.5)

 

 

1.1

Net income (loss)

 

$

258.4

 

$

200.7

 

$

(188.5)

 

$

(1,013.2)

 

$

(56.5)

Net income (loss) attributable to common stockholders (3)

 

$

681.6

 

$

(25.9)

 

$

(370.1)

 

$

(1,158.1)

 

$

(172.4)

Basic and diluted earnings (loss) per share
attributable to common stockholders (4)

 

$

6.54

 

$

(0.50)

 

$

(7.14)

 

$

(22.36)

 

$

(3.33)

Shares used in computing basic and
diluted earnings (loss) per share (4)

 

 

104.2

 

 

51.8

 

 

51.8

 

 

51.8

 

 

51.8

Balance Sheet Data (at end of period):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Cash and cash equivalents

 

$

177.8

 

$

208.1

 

$

160.3

 

$

264.6

 

$

10.5

Total assets

 

$

743.7

 

$

831.0

 

$

616.8

 

$

907.4

 

$

1,902.3

Total debt

 

$

503.2

 

$

1,116.4

 

$

1,188.7

 

$

1,276.2

 

$

972.5

Convertible preferred stock (5)

 

$

 —

 

$

349.8

 

$

349.8

 

$

349.8

 

$

349.8

Total stockholders’ equity (deficit)

 

$

106.9

 

$

(818.3)

 

$

(1,019.0)

 

$

(830.5)

 

$

181.0

Other Data:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Adjusted EBITDA (6)

 

$

419.3

 

$

372.7

 

$

(50.8)

 

$

(62.8)

 

$

359.3

Net debt (at end of period) (7)

 

$

330.1

 

$

921.9

 

$

1,047.0

 

$

1,035.4

 

$

979.5

Capital expenditures

 

$

100.5

 

$

64.0

 

$

10.3

 

$

79.1

 

$

112.2

Total fracturing stages (8)

 

 

30,537

 

 

30,920

 

 

16,185

 

 

21,919

 

 

26,182


(1)

In 2014, this amount related to non-essential equipment and real property we identified to sell. In 2015, this amount includes $572.9 million of impairments related to goodwill, intangible assets, and property and equipment; a $24.5 million write-down of excess inventory; $13.1 million of employee severance costs; $11.0 million of supply commitment charges related to our firm purchase commitments for fracturing sand; $1.8 million of lease abandonment charges; and a gain of $3.4 million related to an acquisition earn-out adjustment. For a discussion of amounts recorded for the three years ended December 31, 2018, see Note 8  “Impairments and Other Charges” in Notes to our Consolidated Financial Statements included elsewhere in this annual report on Form 10-K.

(2)

Consists primarily of state margin taxes accounted for as income taxes. The tax effect of our net operating losses has not been reflected in our results because we have recorded a full valuation allowance with regards to the realization of our deferred tax assets since 2012.

(3)

In 2018, this amount includes a $423.2 million net gain to common stockholders on the recapitalization of our convertible preferred stock to common stock. For previous years, this amount is calculated by subtracting an

32


 

accreted value attributable to our convertible preferred stock from net income or loss. The annual accretion amount was $226.6 million in 2017, $181.6 million in 2016, $144.9 million in 2015, and $115.9 million in 2014. For more information about the convertible preferred stock accretion, see footnote 5 below, and Note 5  “Stockholders’ Equity (Deficit)” and Note 15  “Earnings (Loss) Per Share” in Notes to our Consolidated Financial Statements included elsewhere in this annual report on Form 10-K.

(4)

For 2017 and previous periods, earnings per share and the related shares used to compute earnings per share have been adjusted to give effect to a 69.258777 : 1 reverse stock split that occurred in February 2018 in connection with the completion of our IPO. See Note 5  “Stockholders’ Equity (Deficit)” and Note 14  “Earnings (Loss) Per Share” in Notes to our Consolidated Financial Statements included elsewhere in this annual report on Form 10-K for more information.

(5)

The holders of the convertible preferred stock were also common stockholders of the Company and, prior to the completion of our IPO, collectively appointed 100% of our board of directors. Therefore, the convertible preferred stockholders could have directed the Company to redeem the convertible preferred stock at any time after all of our debt had been repaid; however, we did not consider this to be probable for any of the periods presented due to the amount of debt outstanding. Therefore, we presented the convertible preferred stock as temporary equity but did not reflected any accretion of the convertible preferred stock in this table. See Note 5  “Stockholders’ Equity (Deficit)” and Note 14  “Earnings (Loss) Per Share” in Notes to our Consolidated Financial Statements included elsewhere in this annual report on Form 10-K for more information. The convertible preferred stock was recapitalized to common stock in connection with our IPO in 2018.

(6)

Adjusted EBITDA is a non-GAAP financial measure that we define as earnings before interest; income taxes; and depreciation and amortization, as well as, the following items, if applicable: gain or loss on disposal of assets; debt extinguishment gains or losses; inventory write-downs, asset and goodwill impairments; gain on insurance recoveries; acquisition earn-out adjustments; stock-based compensation; and acquisition or disposition transaction costs. The most comparable financial measure to Adjusted EBITDA under GAAP is net income or loss. Adjusted EBITDA is used by management to evaluate the operating performance of our business for comparable periods and it is a metric used for management incentive compensation. Adjusted EBITDA should not be used by investors or others as the sole basis for formulating investment decisions, as it excludes a number of important items. We believe Adjusted EBITDA is an important indicator of operating performance because it excludes the effects of our capital structure and certain non-cash items from our operating results. Adjusted EBITDA is also commonly used by investors in the oilfield services industry to measure a company’s operating performance, although our definition of Adjusted EBITDA may differ from other industry peer companies.

 

The following table reconciles our net income (loss) to Adjusted EBITDA:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Year Ended December 31,

(In millions)

  

2018

  

2017

  

2016

  

2015

  

2014

Net income (loss)

 

$

258.4

 

$

200.7

 

$

(188.5)

 

$

(1,013.2)

 

$

(56.5)

Interest expense, net

 

 

49.3

 

 

86.7

 

 

87.5

 

 

77.2

 

 

74.2

Income tax expense (benefit)

 

 

2.0

 

 

1.6

 

 

(1.6)

 

 

(1.5)

 

 

1.1

Depreciation and amortization

 

 

84.7

 

 

86.6

 

 

112.6

 

 

272.4

 

 

294.4

(Gain) loss on disposal of assets, net

 

 

(0.1)

 

 

(1.4)

 

 

1.0

 

 

5.9

 

 

5.8

Loss (gain) on extinguishment of debt, net

 

 

9.8

 

 

1.4

 

 

(53.7)

 

 

0.6

 

 

28.4

Inventory write-down

 

 

 —

 

 

 —

 

 

 —

 

 

24.5

 

 

 —

Impairment of assets and goodwill

 

 

 —

 

 

 —

 

 

7.0

 

 

572.9

 

 

9.8

Gain on insurance recoveries

 

 

 —

 

 

(2.9)

 

 

(15.1)

 

 

 —

 

 

 —

Acquisition earn-out adjustments

 

 

 —

 

 

 —

 

 

 —

 

 

(3.4)

 

 

 —

Stock-based compensation

 

 

15.2

 

 

 —

 

 

 —

 

 

1.8

 

 

2.1

Adjusted EBITDA

 

$

419.3

 

$

372.7

 

$

(50.8)

 

$

(62.8)

 

$

359.3

 

(7)

Net debt is a non-GAAP financial measure that we define as total principal amount of debt less cash and cash equivalents. The most comparable financial measure to net debt under GAAP is debt. Net debt is used by management as a measure of our financial leverage. Net debt should not be used by investors or others as the sole basis in formulating investment decisions as it does not represent our actual indebtedness. The following table reconciles our total debt to net debt:

33


 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

December 31,

(In millions)

  

2018

  

2017

  

2016

  

2015

  

2014

Total debt

 

$

503.2

 

$

1,116.4

 

$

1,188.7

 

$

1,276.2

 

$

972.5

Add: unamortized discount and debt issuance costs

 

 

4.7

 

 

13.6

 

 

18.6

 

 

23.8

 

 

17.5

Total principal amount of debt

 

 

507.9

 

 

1,130.0

 

 

1,207.3

 

 

1,300.0

 

 

990.0

Less: cash and cash equivalents

 

 

(177.8)

 

 

(208.1)

 

 

(160.3)

 

 

(264.6)

 

 

(10.5)

Net debt

 

$

330.1

 

$

921.9

 

$

1,047.0

 

$

1,035.4

 

$

979.5

 

(8)

See “Business Our Services Hydraulic Fracturing” in Item 1 of this annual report regarding fracturing stages and the types of service agreements we use to provide hydraulic fracturing services.

 

34


 

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 consolidated financial statements and related notes that appear elsewhere in this annual report on Form 10-K. In addition to historical consolidated financial information, the following discussion contains forward-looking statements that reflect our plans, estimates, or beliefs. Actual results could differ materially from those discussed in the forward-looking statements. Factors that could cause or contribute to these differences include those discussed below and elsewhere in this annual report on Form 10-K, particularly in “Risk Factors.”

Overview

We are one of the largest providers of hydraulic fracturing services in North America. Our services enhance hydrocarbon flow from oil and natural gas wells drilled by exploration and production companies in shale and other unconventional resource formations. We have 1.7 million total hydraulic horsepower across 34 fleets, with 19 fleets active and one fleet under construction and awaiting final assembly as of December 31, 2018. Our customers include leading exploration and production companies that extract oil and natural gas resources in North America. We operate in five of the most active major basins in the United States: the Permian Basin, the SCOOP/STACK Formation, the Marcellus/Utica Shale, the Eagle Ford Shale and the Haynesville Shale. Substantially all of our business activities support our well completion services.

Summary Financial Results

·

Total revenue for 2018 was $1,543.3 million, which represented an increase of $77.2 million from 2017.

·

Net income for 2018 was $258.4 million, which represented an increase of $57.7 million from 2017.

·

Adjusted EBITDA for 2018 was $419.3 million, which represented an increase of $46.6 million from 2017.

·

Cash provided by operating activities for 2018 was $384.8 million, which represented an increase of $204.8 million from 2017.

·

Total principal amount of long-term debt was $507.9 million at December 31, 2018, which represented a decrease of $622.1 million from December 31, 2017.

Industry trends and business outlook

Our business depends on the willingness of E&P companies to make expenditures to explore for, develop, and produce oil and natural gas in the United States. The willingness of E&P companies to undertake these activities is predominantly influenced by current and expected future prices for oil and natural gas. A widely watched indicator of E&P companies’ aggregate activity levels is the drilling rig count, or rig count. The active horizontal rig count is a subset of the total rig count and is the most strongly correlated with the aggregate industry demand for hydraulic fracturing services.

The average horizontal rig count was approximately 900, 735, and 400 in 2018, 2017 and 2016, respectively, according to a report by Baker Hughes, a GE company. The horizontal rig count was 945 at the end of 2018, which was its highest level since the first quarter of 2015. Over this period, drilling rigs have become more efficient and are drilling more wells per rig. In addition, the well designs being drilled have longer lateral lengths and E&P companies have used increasing amounts of sand in each well that they hydraulically fracture. The combination of these factors increased the aggregate demand for hydraulic fracturing services over this period to record levels.

The prices that we are able to charge for our services is affected by the supply of hydraulic fracturing equipment that is available in the market to meet customer demand. In the downturn of 2016, the excess supply of equipment in the market drove our prices down. In 2017, a severe shortage of equipment drove our prices up. The market imbalance in 2017 prompted both existing and new competitors to deploy additional equipment into the market. This increasing supply of active equipment, combined with certain E&P companies reducing their completions activity

35


 

for operational reasons or to better match capital expenditures with their cash flows, caused the supply of equipment to exceed the demand for equipment in the second half of 2018. As a result, the pricing for our services declined in the second half of 2018 and we expect it to decline further in the first quarter of 2019. While we believe demand will remain strong, the supply of equipment in the market has also increased to record levels.

In response to this increasingly competitive market environment, we remain disciplined with respect to our number of active fleets and we remain focused on optimizing our utilization and profitability. We reduced our active fleet count from 28 fleets in the second quarter of 2018 to 19 fleets at the end of the fourth quarter of 2018 because certain fleets did not meet our utilization and profitability targets.

In 2019, we expect for E&P activity levels to remain strong and for us to have continued profitability and cash generation. Based on discussions with our customers, we anticipate activating one or two fleets in the first quarter of 2019. We will continue to manage our active capacity to best match demand from our customers and maximize our profitability and cash flow.

Other significant developments in 2018

·

In February 2018, we completed an IPO of 22.4 million shares of common stock of which 18.1 million shares were sold by the Company. The Company received net proceeds from the offering of $303.0 million, and we used the net proceeds from the offering for general corporate purposes, primarily debt repayments.

·

In February 2018, we entered into a $250 million asset-based revolving credit facility to increase our available liquidity.

Results of Operations

Revenue

The Company contracts with its customers to perform hydraulic fracturing services and wireline services on one or more oil or natural gas wells. Under these arrangements, we satisfy our performance obligations as services are rendered, which is generally upon the completion of a fracturing stage. We typically complete one or more stages per day. The price for our services typically includes an equipment charge and, if applicable, product charges for proppant, chemicals and other products actually consumed during the course of providing our services. The following table includes certain operating statistics that affect our revenue:

 

 

 

 

 

 

 

 

 

 

 

 

Year Ended December 31,

(Dollars in millions)

  

2018

  

2017

  

2016

Revenue

 

$

1,450.4

 

$

1,352.7

 

$

529.5

Revenue from related parties

 

 

92.9

 

 

113.4

 

 

2.7

Total revenue

 

$

1,543.3

 

$

1,466.1

 

$

532.2

 

 

 

 

 

 

 

 

 

 

Total fracturing stages

 

 

30,537

 

 

30,920

 

 

16,185

Active fleets (1)

 

 

24.2

 

 

23.3

 

 

15.6

Total fleets (2)

 

 

34.0

 

 

32.0

 

 

32.0


(1)

Active fleets is the average number of fleets operating during the period. We had 19, 27 and 17 active fleets at December 31, 2018, 2017 and 2016, respectively.

(2)

Total fleets is the total number of fleets owned during the period. In 2018, we had one fleet under construction and awaiting final assembly.

Total revenue in 2018 increased by $77.2 million from 2017. This increase was primarily due to higher average pricing for our services in 2018 compared to 2017. Pricing for our services increased in each quarter of 2017 and the first quarter of 2018, but decreased for the remaining quarters of 2018. The increased average pricing of our services during

36


 

2018 was partially offset by an increase in the portion of customers who provided their own proppant and a decrease in the cost of materials used in the fracturing process during 2018. The average number of active fleets operating during all of 2018 increased slightly from 2017. The number of fracturing stages completed per average active fleet in 2018 decreased by 5% from 2017. This decrease was primarily due to a high level of utilization in the second and early third quarters of 2017, which was driven by a significant shortage of active hydraulic fracturing equipment in the market.

At December 31, 2018, we evaluated all of our idle fleets and concluded that each of these fleets is available to return to service after our maintenance personnel make any necessary repairs and confirm that the equipment is in operating condition.

The decrease in revenue from related parties in 2018 was due to a decrease in services performed for Chesapeake.

Total revenue in 2017 increased by $933.9 million from 2016. This increase was primarily due to an increase in the number of stages completed and an increase in the prices for our services in 2017, both of which were driven by increased customer demand. The number of active fleets operating during 2017 increased by an average of 7.7 fleets from 2016, due to increased customer demand. The number of fracturing stages completed per average active fleet in 2017 increased by 28% from 2016. This increase was due to higher levels of utilization in 2017 as we recovered from the 2016 industry downturn.

The increase in revenue from related parties in 2017 was due to an increase in the services performed for Chesapeake.

Costs of revenue

The primary costs involved in conducting our hydraulic fracturing services are costs for materials used in the fracturing process and costs to operate, maintain, and repair our fracturing equipment. Costs related to the materials used in the fracturing process typically include costs for sand and other proppants, costs for chemicals added to the fracturing fluid, and freight costs to transport these materials to the well location. Costs to operate our fracturing equipment primarily consist of labor and fuel costs. While we exclude certain amounts of depreciation and amortization from our costs of revenue line item, we have included the amounts of depreciation that specifically relate to our revenue generating assets in our discussion below to provide further information regarding the total costs of generating our revenues. Costs of revenue as a percentage of total revenue is as follows:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Year Ended December 31,

 

 

 

2018

 

 

2017

 

 

2016

 

 

 

 

 

 

As a Percent

 

 

 

 

As a Percent

 

 

 

 

As a Percent

 

(Dollars in millions)

  

Dollars

  

of Revenue

  

 

Dollars

 

of Revenue

 

Dollars

  

of Revenue

 

Costs of revenue, excluding depreciation

 

$

1,033.2

 

66.9

 

$

1,009.8

 

68.9

%

 

$

510.5

 

95.9

%

Depreciation — costs of revenue

 

 

75.9

 

5.0

 

 

75.6

 

5.1

%

 

 

98.9

 

18.6

%

Total costs of revenue

 

$

1,109.1

 

71.9

 

$

1,085.4

 

74.0

%

 

$

609.4

 

114.5

%

 

Total costs of revenue in 2018 increased by $23.7 million from 2017. This increase was primarily due to an increase in our costs of revenue, excluding depreciation.

Costs of revenue, excluding depreciation, in 2018 increased by $23.4 million from 2017. This increase was primarily due to our higher average number of active fleets in 2018. This increase was partially offset by an increase in the portion of customers who provided their own proppant and a decrease in the costs for materials used in the fracturing process in the second half of 2018, when compared to the same period in 2017.

Depreciation for our service equipment in 2018 increased by $0.3 million from 2017.

37


 

Total costs of revenue as a percentage of total revenue decreased by 2.1 percentage points from 74.0% in 2017 to 71.9% in 2018. This change was primarily due to an increase in the average pricing for our services in 2018 when compared to 2017.

Total costs of revenue in 2017 increased by $476.0 million from 2016. This increase was primarily due to an increase in our costs of revenue, excluding depreciation, which were partially offset by a decrease in the depreciation expense for our service equipment.

Costs of revenue, excluding depreciation, in 2017 increased by $499.3 million from 2016, due to our higher number of active fleets, increased number of stages completed during 2017, and increased costs for materials used in the fracturing process. Depreciation for our service equipment in 2017 decreased by $23.3 million from 2016. This decrease was the result of asset disposals and certain assets becoming fully depreciated. Additionally, we generally refurbish our equipment as it approaches the end of its useful life, rather than replacing it by purchasing new equipment. The cost of refurbishing our equipment is significantly lower than the cost of purchasing new equipment. As more of our fleets became comprised of refurbished assets in recent years, our depreciation correspondingly declined.

Total costs of revenue as a percentage of total revenue decreased by 40.5 percentage points from 114.5% in 2016 to 74.0% in 2017. This change was primarily due to increased pricing for our services and increased stages completed per active fleet in 2017. These factors were partially offset by increased costs for materials used in the fracturing process.

Selling, general and administrative expense

Selling, general and administrative (“SG&A”) expense in 2018 increased by $6.9 million from 2017. This increase was primarily due to stock-based compensation expense incurred in 2018. We incurred $3.7 million of expense to cash-settle all remaining unvested awards from our 2014 Long Term Incentive Plan, which vested upon the completion of our IPO. We also incurred $15.2 million of non-cash expense related to RSU awards granted in 2018. These increases were partially offset by decreased cash-based incentive compensation expense in 2018.

Selling, general and administrative expense in 2017 increased by $16.6 million from 2016. This increase was primarily due to increased incentive compensation related to our improved operating results in 2017 and increased employee-related costs due to our increased overall headcount in 2017.

Depreciation and amortization

The following table summarizes our depreciation and amortization:

 

 

 

 

 

 

 

 

 

 

 

 

Year Ended December 31,

(In millions)

  

2018

  

2017

  

2016

Depreciation — costs of revenue (1)

 

$

75.9

 

$

75.6

 

$

98.9

Depreciation — other (2)

 

 

8.8

 

 

11.0

 

 

13.7

Total depreciation and amortization

 

$

84.7

 

$

86.6

 

$

112.6


(1)

Related to service equipment included in “Property, plant, and equipment, net” on our consolidated balance sheets discussed under the “Costs of revenue” heading of this discussion and analysis.

(2)

Related to all long-lived assets other than service equipment included in “Property, plant, and equipment, net” on our consolidated balance sheet.

Depreciation and amortization in 2018 decreased by $1.9 million from 2017. This decrease was primarily due to asset disposals and certain assets, other than service equipment, becoming fully depreciated.

Depreciation and amortization in 2017 decreased by $26.0 million from 2016. This decrease was primarily due to a decrease in depreciation for our service equipment as previously discussed. The remaining decrease was primarily due to asset disposals and certain assets becoming fully depreciated.

38


 

Impairments and other charges

The following table summarizes our impairments and other charges:

 

 

 

 

 

 

 

 

 

 

 

 

Year Ended December 31,

(In millions)

  

2018

  

2017

  

2016

Supply commitment charges

 

$

19.2

 

$

1.2

 

$

2.5

Impairment of assets

 

 

 —

 

 

 —

 

 

7.0

Employee severance costs

 

 

 —

 

 

 —

 

 

0.8

Lease abandonment charges

 

 

 —

 

 

0.6

 

 

2.0

Total impairments and other charges

 

$

19.2

 

$

1.8

 

$

12.3

 

Supply Commitment Charges : We incur supply commitment charges when our purchases of proppant from certain suppliers are less than the minimum purchase commitments in our supply contracts. According to the accounting guidance for firm purchase commitments, future charges that are considered likely are also required to be recorded in the current period.

We recorded aggregate charges under these supply contracts of $19.2 million, $1.2 million and $2.5 million in 2018, 2017 and 2016, respectively. These charges related to actual purchase shortfalls incurred, as well as forecasted purchase shortfalls that are expected to be incurred and settled in future periods. Approximately $12 million of our 2018 supply commitment charges relate to estimated losses under these contracts for 2019. These purchase shortfalls are due to our customers choosing to provide their own proppant, our customers’ desire to purchase sand from sand mines closer to their operating areas, increased purchase commitments in 2019, and low activity levels in 2016.

A significant majority of our contracted proppant is for sand types that are mined primarily in the Midwestern United States (“Northern White” sand). Since we executed these contracts, customer demand for sand has shifted away from Northern White sand and towards lower-cost sand that is available from sand mines closer in proximity to our customers’ operating locations. We are in discussions with our vendors to modify our supply contracts to better align with our customers’ volume requirements, preferred sand types, and preferred sand mine locations.

Estimated losses related to these supply contracts contain uncertainties, such as future customer demand, future customer sand preferences, the legal defenses available to us, and the outcome of our ongoing vendor discussions. These uncertainties require us to use judgment to quantify the amount of these estimates. Actual results could materially differ from our estimate.

While we have successfully worked with our vendors to minimize charges related to these purchase commitments in the past, if we do not meet the minimum purchase commitments in the future and we are unable to adjust or avoid our contracted amounts, we may incur additional supply commitment charges in future periods.

Impairment of Assets : During 2016, we recorded asset impairments of $7.0 million related to service equipment and real property that we no longer use and identified to sell.

Lease Abandonment Charges : During 2016, we vacated certain leased facilities to consolidate our operations. In 2017 and 2016, we recognized expense of $0.6 million and $2.0 million, respectively, in connection with these actions.

Employee Severance Costs : During 2016, we incurred employee severance costs of $0.8 million in connection with our corporate and operating restructuring initiatives. At December 31, 2016, we had paid substantially all severance payments owed to former employees.

Loss on disposal of assets, net

During 2017 and 2016, we sold a number of surplus pieces of property and equipment. In 2017, we received $4.1 million of proceeds and recognized a $1.4 million net gain on the sale of these assets. In 2016, we received $23.5

39


 

million of proceeds and recognized a $1.3 million net loss on the sale of these assets. In February 2016, we sold substantially all of our remaining sand transportation equipment and related inventory. We received $8.0 million of proceeds and recognized a $0.3 million gain on this sale.

Gain on insurance recoveries

In January 2017, a fire destroyed certain equipment in one of our fleets. These assets were insured at values greater than their carrying values. We received $4.2 million of insurance recovery proceeds for these assets, which exceeded their carrying values by $2.9 million.

In January 2016, a fire at one of our job sites in Oklahoma destroyed substantially all of the equipment in one of our fleets. These assets were insured at values greater than their carrying values. We received $19.0 million of insurance recovery proceeds for these assets, which exceeded their carrying values by $15.1 million.

Interest expense, net

Interest expense, net of interest income, in 2018 decreased by $37.4 million from 2017. This decrease was primarily due to a lower average debt balance in 2018, after the repayment of $622.1 million of aggregate principal amount of long-term debt.

Interest expense, net of interest income, in 2017 decreased by $0.8 million from 2016. This decrease was primarily due to a lower average long-term debt balance, which was partially offset by higher average interest rates in 2017 for our senior floating rate notes due June 2020.

Gain (loss) on extinguishment of debt, net

In 2018, we repaid $310.0 million of aggregate principal amount of Term Loan. We recognized a loss on debt extinguishment of $2.7 million. In 2018, we repaid all $290.0 million remaining principal amount of our floating rate senior notes due in 2020 using cash on hand and proceeds received from our IPO. We recognized a loss on this debt extinguishment of $8.3 million.  In 2018, we repurchased $22.1 million of aggregate principal amount of 2022 Senior Notes in the qualified institutional market. We recognized a gain on debt extinguishment of $1.2 million.

In 2017, we repaid $60.0 million of aggregate principal amount of our senior floating rate notes due June 2020. We recognized a loss on debt extinguishment of $1.8 million. In 2017, we also repurchased $17.3 million of aggregate principal amount of senior notes due May 2022 in the qualified institutional market. We recognized a gain on debt extinguishment of $0.4 million.

In the third quarter of 2016, we completed a tender offer and subsequent purchases in the qualified institutional market for a portion of our long-term debt in which we repurchased $90.7 million of aggregate principal amount of long-term debt and recorded a gain on debt extinguishment of $52.3 million.

Income tax expense

Income tax expense was $2.0 million and $1.6 million in 2018 and 2017, respectively. These amounts consisted of state margin taxes accounted for as income taxes and income taxes for states that limit the deduction of net operating loss carryforwards. In 2012, we recorded a valuation allowance to reduce our net deferred tax assets to zero. We continue to provide a valuation allowance against all deferred tax assets in excess of our deferred tax liabilities. As a result, we did not record any U.S. federal or other state income tax expense or benefit related to our income or losses in 2018, 2017 or 2016. See Note 11 — “Income Taxes” in Notes to our Consolidated Financial Statements included elsewhere in this annual report on Form 10-K for more information regarding our income taxes and valuation allowance.

40


 

Liquidity and Capital Resources

Sources of Liquidity

At December 31, 2018, we had $177.8 million of cash and cash equivalents. As of February 28, 2019, we had $106.1 million available for borrowings under our revolving credit facility. We believe that our cash and cash equivalents, cash provided by operations, and the availability under our revolving credit facility will be sufficient to fund our operations and capital expenditures for at least the next 12 months.

In February 2018, we entered into a $250 million asset-based revolving credit facility. The maximum availability of credit under the credit facility is limited at any time to the lesser of $250 million or the borrowing base. The borrowing base is based on percentages of eligible accounts receivable and eligible inventory and is subject to certain reserves. As of February 28, 2019, our borrowing base was $113.2 million and therefore our maximum availability under the credit facility was $113.2 million. As of February 28, 2019, there were no borrowings outstanding under the credit facility, and letters of credit totaling $7.1 million were issued, resulting in $106.1 million of availability under the credit facility.

In an event of default or if the amount available under our credit facility is less than either 10% of our maximum availability or $12.5 million, we will be required to maintain a minimum fixed charge coverage ratio of 1.0 to 1.0. If at any time borrowings and letters of credit issued under the credit facility exceed the borrowing base, we will be required to repay an amount equal to such excess. See Note 4 — “Indebtedness and Borrowing Facility” in notes to our consolidated financial statements included elsewhere in this annual report on Form 10-K for more information on our credit facility.

Cash Flows

The following table summarizes our cash flows:

 

 

 

 

 

 

 

 

 

 

 

 

Year Ended December 31,

(In millions)

  

2018

  

2017

  

2016

Net income (loss) adjusted for non-cash items

 

$

368.9

 

$

288.8

 

$

(130.9)

Changes in operating assets and liabilities

 

 

15.9

 

 

(108.8)

 

 

21.1

Net cash provided by (used in) operating activities

 

 

384.8

 

 

180.0

 

 

(109.8)

Net cash (used in) provided by investing activities

 

 

(98.6)

 

 

(54.6)

 

 

40.2

Net cash used in financing activities

 

 

(325.6)