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. Our customers include Chesapeake Energy Corporation, ConocoPhillips, Devon Energy Corporation, EOG Resources, Inc., Diamondback Energy Inc., EQT Company, Range Resources Corporation, and other leading E&P companies that specialize in unconventional oil and natural gas resources in North America.
We have 1.6 million total hydraulic horsepower across 32 fleets, with 27 fleets active as of December 31, 2017. As one of the largest hydraulic fracturing service providers in North America, we believe we are well positioned to capitalize on the recovery of the North American oil and natural gas exploration and production market.
We are one of the top three hydraulic fracturing providers across our operating footprint, which consists of 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. Our market share and our large-scale operating presence across a variety of active basins provides us with important strategic advantages, such as: the ability to serve large, multi-basin customers; better negotiating power with our customers and suppliers; reduced volatility in our activity levels as completions activity endures cycles in different basins; and a lower relative cost structure for fixed overhead and corporate costs.
The following map shows the basins in which we operate and the number of fleets operated from each basin as of December 31, 2017.
We are experiencing a surge in demand for our services, which has led us to reactivate 10 fleets since the beginning of 2017. Based on continued requests from customers for additional fleets, we are in the process of reactivating additional equipment at our in-house manufacturing facility. The surge in demand for our services has allowed us to raise prices significantly. Oil prices have more than doubled since the 12-year low of $26.14 in February 2016, reaching a high of $64.89 in January 2018 and averaging $50.80 in 2017. Similarly, the U.S. horizontal rig count has increased by 155%, from a low of 314 rigs as of May 27, 2016 to 802 rigs as of January 19, 2018, according to an industry report. The large growth in E&P drilling activity has caused demand for pressure pumping services to exceed the supply of readily available fleets, which has led average pricing for our services to rise more than approximately 56% from the fourth quarter of 2016. These price increases started in January 2017 and continued to progress to higher levels throughout 2017.
During the last two years, we implemented measures to reduce our operating costs and to improve our operating efficiency, including reducing the number of our active fleets as demand for our services declined. We focused on our ability to operate our active fleets for as many hours per day and days per month as possible in order to limit the non-productive time of our active fleets. As a result, we have increased our average stages per active fleet per quarter to record levels. These operational improvements occurred despite significant reductions in our operating costs, including reducing our quarterly selling, general and administrative expense by approximately 60% from 2014 levels.
We maintained these improved cost and efficiency levels in 2017, which, combined with the recent rise in pricing for our services, allowed us to achieve EBITDA levels greater than what we experienced in 2014. We achieved these results despite having
considerably lower pricing and fewer active fleets on average than we had in 2014. We believe we can continue to sustain these cost reductions and efficiency improvements as activity levels increase.
Our customers typically compensate us based on the number of stages fractured and the primary contributor to the number of stages we complete is our ability to reduce downtime on our equipment. As a result, we believe the number of stages fractured and the average number of stages completed per active fleet in a given period of time are important operating metrics for our business. The graphs below show the number of stages we completed per quarter and the average stages per active fleet we completed per quarter. For additional information regarding our fleet capacity and average stages per active fleet per quarter as an operating metric, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations-Results of Operations-Revenue” and “-Our Services-Hydraulic Fracturing” in Item 7 of this annual report.
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% to 60% less than purchasing them from outside suppliers. We estimate that our cost advantage saves us approximately $85 million per year at peak production levels. In addition, we perform full-scale refurbishments of our fracturing units at a cost that is approximately half the cost of utilizing an outside supplier.
Our manufacturing capabilities also reduce the risk that we will be unable to source important components, such as fluid-ends, power-ends and other consumable parts. During periods of high demand for hydraulic fracturing services, external equipment vendors often report order backlogs of up to nine months. Our competitors may be unable to source components when needed or may be required to pay a much higher price for their components, or both, due to bottlenecks in supplier production levels. We have historically manufactured, and believe we have the capacity to manufacture, all major consumable components required to operate all 32 of our fleets at full capacity. We designed and assembled all of our 32 existing fleets using internal resources and we believe we could 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 hydraulic fracturing equipment. We designed our equipment to uniform specifications intended specifically for completions work in oil and natural gas basins 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 HSE conditions at our well sites. We help customers monitor and modify fracturing fluids and designs, through our fluid research and development operations that we conduct through a strategic partnership with a third-party technology center that utilizes key employees who were previously affiliated with our Company. In June 2017, we renewed our services agreement with this third-party technology center for a one-year term, with an option for us to renew for additional one-year terms. This partnership allows us to work closely with our customers to rapidly adopt and integrate next-generation fluid breakthroughs, such as our NuFlo® 1000 fracturing fluid diverter, into our product offerings.
We own a 45% interest in SinoFTS, which is a Chinese joint venture that we formed in June 2014 with Sinopec. SinoFTS fractured its first wells in China in 2016. Although we do not expect rapid short-term growth, this joint venture provides us with experience in overseas operations that could be beneficial to us if hydraulic fracturing activity begins to grow significantly in international markets.
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, and our customers typically compensate us based on each stage completed. Although the number and length of stages may vary by basin and formation characteristics, we have historically maintained a relatively consistent presence in each operating basin. 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 16%. Despite the longer average stage lengths, we have been able to increase our average stages per active fleet compared to the end of 2014. 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 downtime on our equipment, rather than any variability in operating basins or formation characteristics. Therefore, we believe the number of stages that each of our active fleets completes in a given period of time is an important operating metric.
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 the formation. The fracturing fluid primarily consists of water mixed with a small amount of chemicals and guar, forming a highly viscous liquid. Materials known as proppants, in our case primarily sand, are suspended in the fracturing fluid and are pumped into the fracture to prop it open. Once the fractures are open, the fluid is designed to “break,” or reduce its viscosity, so that it will more easily flow back out of the formation. The proppants, which remain behind in the formation, act as a wedge that keeps the fractures open, allowing the trapped hydrocarbons to flow more freely. 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, with production from a shale well typically falling 60% to 70% in the first year. As a result, E&P companies must fracture new wells to maintain production levels.
We designed all of the hydraulic fracturing units and much of the auxiliary equipment used in our fleets to uniform specifications intended specifically for work in oil and natural gas basins requiring high pressures and high levels of sand intensity. Each of our fleets typically consists of 16 to 25 hydraulic fracturing units; two or more blenders (one used as a backup), which blend the proppant and chemicals into the hydraulic fluid; sand kings and other types of large containers used to store sand on location; various vehicles used to transport chemicals, gels and other materials; and various service trucks. 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 an assigned coordinator at our headquarters for display in both digital and graphical form.
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.
We primarily enter into service agreements with our customers for one or more “dedicated” fleets, rather than providing our fleets primarily 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-Revenue Recognition” in Notes
to our Audited Consolidated Financial Statements for discussion of pricing under our service agreements and revenue recognized for services.
An important element of hydraulic fracturing is the proper handling of the fracturing fluid. In all of our hydraulic fracturing jobs, our customers specify the composition of the fracturing fluid to be used. Sometimes this fluid includes products marketed by us. 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. 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.
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. We currently provide wireline services in each of the areas where our hydraulic fracturing fleets operate. As of December 31, 2017, we owned 51 wireline units.
Industry Overview and Trends
The oil and natural gas industry has traditionally been volatile and is influenced by a combination of long-term, short-term and cyclical trends, including the domestic and international supply and demand for oil and natural gas, current and expected future prices for oil and natural gas and the perceived stability and sustainability of those prices, production depletion rates and the resultant levels of cash flows generated and allocated by E&P companies to their well completions budget. The oil and natural gas industry is also impacted by general domestic and international economic conditions, political instability in oil producing countries, government regulations (both in the United States and elsewhere), levels of customer demand, the availability of pipeline capacity and other conditions and factors that are beyond our control.
The principal factor influencing demand for hydraulic fracturing services is the level of horizontal drilling activity by E&P companies. Since 2006, these companies have increasingly focused on exploiting the hydrocarbon reserves contained in North America’s unconventional oil and natural gas reservoirs by utilizing horizontal drilling and hydraulic fracturing. Over the last decade, advances in these technologies have made the development of many unconventional resources, such as oil and natural gas shale formations, economically attractive. These advancements led to a dramatic increase in the development of oil- and natural gas-producing basins in the United States and a corresponding increase in the demand for hydraulic fracturing services. Our industry grew rapidly until a significant decline in oil and natural gas prices from 2014 to 2016 caused a dramatic reduction in drilling and completion activity.
The significant decline in oil and natural gas prices that began in the third quarter of 2014 continued into February 2016, when the closing price of oil reached a 12-year low of $26.14 in February 2016. The horizontal rig count in the United States declined by 77%, from its peak of 1,372 rigs in November 2014 to a low of 314 rigs in May 2016, according to a Baker Hughes, Inc. report dated January 6, 2017. The reduced drilling activity led to a reduction in demand for hydraulic fracturing services and resulted in increased competition and lower prices for hydraulic fracturing services. The low commodity price environment caused a reduction in the completion activities of most of our customers and their spending on our services, which substantially reduced the prices we could charge our customers and had a negative impact on our activity levels during this period. We believe the financial distress of many other providers of hydraulic fracturing services led to significant maintenance deferrals and the use of idle fleets for spare parts, resulting in a material reduction in total deployable fracturing fleets.
Recently, oil prices have increased since the 12-year low recorded in February 2016, reaching a high of $64.89 in December 2017 and averaging $50.80 in 2017. As commodity prices have rebounded, we have experienced an increase in the level of demand for our services. Although our industry traditionally has been volatile, the following trends in our industry should benefit our operations and our ability to achieve our business objectives as commodity prices recover:
Large production growth from U.S. oil and natural gas formations. The average oil field production in the United States grew at a compound annual growth rate of 8.4% over the period from 2010 through 2016 due to production gains from unconventional reservoirs. According to the U.S. Energy Information Administration, or EIA, U.S. tight oil production grew from approximately 430,000 barrels per day in 2007 to over 4.6 million barrels per day in 2017 through November, representing 70% of total U.S. crude oil production in 2017 (as of the end of November). A majority of this increase came from the Permian Basin, the SCOOP/STACK Formation, the Marcellus/Utica Shale, the Eagle Ford Shale and the Haynesville Shale, which are our five operating basins, as well as
the Williston Basin. We expect that this continued growth will result in increased demand for our services as commodity prices continue to stabilize or increase.
Increased use of horizontal drilling to develop high-pressure U.S. resource basins. The horizontal rig count as a percentage of the overall onshore rig count has increased every year since 2007, when horizontal rigs represented only approximately 25% of the total U.S. onshore rig count to approximately 86% at the end of 2017. We believe horizontal drilling activity will continue to grow as a portion of overall onshore wells drilled in the United States, primarily due to E&P companies increasingly developing unconventional resources such as shales. Successful economic production of these unconventional resource basins frequently requires hydraulic fracturing services like those we provide.
Faster drilling speed. The speed of drilling rigs is increasing significantly, which has increased the number of wells drilled for a given rig count. The speed of drilling means that more fracturing fleets are needed for every active drilling rig. On average there used to be four drilling rigs for each fracturing fleet, but that ratio is now less than 3-to-1, and continuing to decline. As a result, E&P companies are able to complete more stages using fewer rigs, and industry sources expect that total stages completed in 2017 will surpass 2014 levels at a significantly lower corresponding rig count.
Increasing completions intensity. Longer lateral lengths for horizontal wells and more sand per lateral foot require increased horsepower to execute a completion, which means that more fracturing units will be required for each fleet. The increased amount of sand per lateral foot also increases the wear-and-tear on each unit’s components and parts, which increases the repair and maintenance costs for each fleet. We expect that the projected increase in drilling speed and sand intensity will result in an increased demand for, and diminished supply of, pressure pumping services.
Reduced supply of hydraulic fracturing services from our competitors. The hydraulic fracturing industry in the United States is characterized by a few large providers (six with over 1 million horsepower), several medium sized providers (nine with between 1 million and 300,000 horsepower) and a significant number of smaller providers. We believe that many of these providers have been deferring or declining to repair their hydraulic fracturing equipment as it breaks down from ordinary use. This phenomenon of providers choosing to retire rather than repair broken equipment is often referred to as “attrition.” According to an industry report, the total working horsepower in North America declined from approximately 15 million in 2014 to approximately 6 million in 2016. Additionally, the large number of small service providers in our industry may make it an attractive candidate for industry consolidation, which would further reduce competition. These factors should lead to a better balance of supply and demand and to higher pricing levels for our services.
Completion of refracturings and drilled-but-uncompleted wells. As producing shale wells age, their level of production declines, typically falling 60% to 70% in the first year. Refracturing these wells can increase production levels. As the number and age of producing unconventional wells increases, the market for recompletions is expected to increase. In addition, because the cost of recompleting a well is generally lower than the total cost of drilling and completing a new well, the demand for recompletions is expected to increase relative to demand for new completions during depressed commodity price environments.
Potential development of international markets for our hydraulic fracturing services. There has been growing international interest in the development of unconventional resources such as oil and natural gas shales. This interest has resulted in a number of recently completed joint ventures between major U.S. and international E&P companies related to shale basins in the United States and acquisitions of significant acreage in shale basins in the United States by large, non-U.S. E&P companies. We believe that these acquisitions and joint ventures, which generally require the international partner to commit to significant future capital expenditures, will provide additional demand for hydraulic fracturing services in the coming years. Additionally, such activity may stimulate development of oil and natural gas shales outside the United States, such as the recent activity by our SinoFTS joint venture in Chongqing, China.
Increase in demand for oil and natural gas. The EIA projects that the average WTI price will increase through 2040 from growing demand and the development of more costly oil resources. The EIA also anticipates continued growth in long-term U.S. domestic demand for natural gas. We believe that as demand for oil and natural gas increases, E&P activity will rise and demand for our services will increase. Recent events including declines in North American production, attrition in the supply of horsepower in our industry and agreements by OPEC and certain other oil-producing countries to reduce oil production have provided upward momentum for energy prices. If near-term commodity prices stabilize at current levels or recover further, we expect a more active demand environment during 2018 and 2019 than was experienced in 2015 and 2016.
Competitive Strengths
We believe that we are well positioned because of the following competitive strengths:
Large scale and leading market share across five of the most active major U.S. unconventional resource basins
With 1.6 million total hydraulic horsepower in our fleet, we are one of the largest hydraulic fracturing service providers in North America. We operate in five of the most active major unconventional basins in the United States, including the Permian Basin, the SCOOP/STACK Formation, the Marcellus/Utica Shale, the Eagle Ford Shale and the Haynesville Shale, which provide us exposure to a variety of oil and natural gas producers as well as geographies. We are one of the top three hydraulic fracturing providers across this operating footprint based on market share. According to an industry report from December 2017, these five operating basins will account for approximately 80% of well-completions spending in 2018 and 2019.
This geographic diversity reduces the volatility in our revenue due to basin trends, relative oil and natural gas prices, adverse weather and other events. Our five hydraulic fracturing districts enable us to rapidly reposition our fleets based on demand trends among different basins. Additionally, our large market share in each of our operating basins allows us to spread our fixed costs over a greater number of fleets. Furthermore, our large scale strengthens our negotiating position with our suppliers and our customers.
Pure-play, efficient hydraulic fracturing services provider with extensive experience in U.S. unconventional oil and natural gas production
Our primary focus is hydraulic fracturing. For the years ended December 31, 2016 and December 31, 2017, 95% of our revenues came from hydraulic fracturing services. From December 31, 2010 to January 8, 2018, we have completed more than 163,000 fracturing stages across five of the most active major unconventional basins in the United States. This history gives us invaluable experience and operational capabilities that are at the leading edge of horizontal well completions in unconventional formations.
We designed and assembled all of the hydraulic fracturing units and much of the auxiliary equipment used in our fleets to uniform specifications intended specifically for work in oil and natural gas basins requiring high pressures and high levels of sand intensity. In addition, we use proprietary pumps with fluid-ends that are capable of meeting the most demanding pressure, flow rate and proppant loading requirements encountered in the field.
In order to achieve the highest revenue potential and highest returns on our invested capital, we run all of our fleets in 24-hour operations allowing us to optimize the revenue-producing ability of our active fleets. In addition, rather than perform “spot work,” we prefer to dedicate each of our fleets to a specific customer, integrating our fleet into their drilling program schedule. These arrangements allow us to increase the number of days per month that our fleet is generating revenue and allow our crews to better understand customer expectations resulting in improved efficiency and safety.
In-house manufacturing, equipment maintenance and refurbishment capabilities
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 our idle equipment. Our cost to produce components and reactivate idle 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% to 60% less than purchasing them from outside suppliers. In addition, we perform full-scale refurbishments of our fracturing units at a cost that is approximately half the cost of utilizing an outside supplier. We estimate that this cost advantage saves us approximately $85 million per year at peak production levels. As trends in our industry continue toward increasing proppant levels and service intensity, the added wear-and-tear on hydraulic fracturing equipment will increase the rate at which components need to be replaced for a typical fleet, increasing our long-term cost advantage versus our competitors that do not have similar in-house manufacturing capabilities.
Our manufacturing capabilities also reduce the risk that we will be unable to source important components, such as fluid-ends, power-ends and other consumable parts. During periods of high demand for hydraulic fracturing services, external equipment vendors often report order backlogs of up to nine months. Our competitors may be unable to source components when needed or may be required to pay a much higher price for their components, or both, due to bottlenecks in supplier production levels. We have historically manufactured, and believe we have the capacity to manufacture, all major consumable components required to operate all 32 of our fleets at full capacity. We also designed and assembled all of our 32 existing fleets using internal resources and believe we can assemble new fleets internally at a substantial discount to the cost of buying them new from third-party providers.
Additionally, manufacturing our equipment internally allows us to constantly improve our equipment design in response to the knowledge we gain by operating in harsh geological environments under challenging conditions. This rapid feedback loop between our field operations and our manufacturing operations positions our equipment at the leading edge of developments in hydraulic fracturing design.
Uniform fleet of standardized, high specification hydraulic fracturing equipment
We have a uniform fleet of hydraulic fracturing equipment. We designed our equipment to uniform specifications intended specifically for completions work in oil and natural gas basins 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. We believe our technologically advanced fleets are among the most reliable and best performing in the industry with the capabilities to meet the most demanding pressure and flow rate requirements in the field.
Our standardized equipment reduces our downtime as our mechanics can quickly and efficiently diagnose and repair our equipment. Our uniform equipment also reduces the amount of inventory we need on hand. We are able to more easily shift fracturing pumps and other equipment among operating areas as needed to take advantage of market conditions and to replace temporarily damaged equipment. This flexibility allows us to target customers that are offering higher prices for our services, regardless of the basins in which they operate. Standardized equipment also reduces the complexity of our operations, which lowers our training costs. Additionally, we believe our industry-leading safety record is partly attributable to the standardization of our equipment, which makes it easier for mechanics and equipment operators to identify and diagnose problems with equipment before they become safety hazards.
Safety leader
Safety is at the core of our operations. Our safety record for 2016 was the best in our history and we believe significantly better than our industry peer group, based on data provided by reports of the U.S. Bureau of Labor Statistics from 2011 through 2016. For the past three years, we believe our total recordable incident rate was less than half of the industry average. During the first quarter of 2017, we reached a milestone of over 10 million man-hours without a lost time incident. 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.
Experienced management and operating team
During the downturn, our management team focused on reducing costs, increasing operating efficiency and differentiating ourselves through innovation. The team has an extensive and diverse skill set, with an average of over 23 years of professional experience. Our operational and commercial executives have a deep understanding of unconventional resource formations, with an average of approximately 31 years of oil and natural gas industry experience. In addition, as a result of our pure-play focus on hydraulic fracturing and dedicated fleet strategy, our operations teams have extensive knowledge of the geographies in which we operate as well as the technical specifications and other requirements of our customers. We believe this knowledge and experience allows us to service a variety of E&P companies across different basins efficiently and safely.
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:
Capitalize on expected recovery and demand for our services
As demand for oilfield services in the United States recovers, the hydraulic fracturing sector is expected to grow significantly. 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 increase at a compound annual growth rate, or CAGR, of 20.7% from 2016 through 2020. 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 exploration and production market.
We have 1.6 million total hydraulic horsepower across 32 total fleets, with 27 fleets active as of December 31, 2017. A surge in demand for our services led us to reactivate 10 fleets since the beginning of 2017. We are in the process of activating additional fleets based on continued customer interest, and we believe all of this equipment can be returned to service within nine months, if market conditions require. We estimate the average cost to reactivate our inactive fleets to be approximately $6.9 million per fleet, which includes capital expenditures, repairs charged as operating expenses, labor costs and other operating expenses.
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 downtime. 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 downtime 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 downtime 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. We help customers monitor and modify fracturing fluids and designs through our fluid research and development operations that we conduct through a strategic partnership with a third-party technology center that utilizes key employees who were previously affiliated with our Company. In June 2017, we renewed our services agreement with this third-party technology center for a one-year term, with an option for us to renew for additional one-year terms. This partnership allows us to work closely with our customers to rapidly adopt and integrate next-generation fluid breakthroughs, such as our NuFlo® 1000 fracturing fluid diverter, into our product offerings.
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; high-definition cameras to remotely monitor the performance of our equipment; 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 entered into a $250.0 million asset-based revolving credit facility on February 22, 2018. Our focus will be on the continued prudent management of our capital structure. We believe this focus creates potential for significant operating leverage and strong free cash flow generation during an industry upcycle. As a result, 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. If we are able to sufficiently reduce our indebtedness and continue to generate cash flow from operations, we expect to return value to shareholders, including by means of cash returns, accretive acquisitions that fit our model and footprint, or the construction of new fleets depending on our business outlook. See “Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities - Dividends” in Item 5 of this annual report and “Risk Factors - Risks Relating to Our Indebtedness” in Item 1A
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 significantly declined in 2015 and 2016.
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;
· the level of global and domestic oil and natural gas inventories;
· the supply of and demand for hydraulic fracturing and other oilfield services and equipment in the United States;
· the cost of exploring for, developing, producing and delivering oil and natural gas;
· available pipeline, storage and other transportation capacity;
· lead times associated with acquiring equipment and products and availability of qualified personnel;
· the discovery rates of new oil and natural gas reserves;
· federal, state and local regulation of hydraulic fracturing and other oilfield service activities, as well as 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 declined significantly in 2015 and 2016 and remain volatile, which has adversely affected, and may continue to 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. For example, oil prices declined significantly in 2015 and 2016, with WTI crude oil spot prices declining from a monthly average of $105.79 per barrel in June 2014 to $26.14 per barrel in February 2016. The spot price per barrel as of December 29, 2017 was $60.42. In line with this sustained volatility in oil and natural gas prices, we experienced a significant decline in pressure pumping activity levels across our customer base. 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 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 competition during the recent downturn, we had to lower the prices for our services. In future downturns, 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 recent industry downturn 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. For the years ended December 31, 2016 and December 31, 2017, our four largest customers generated approximately 52% and 32%, respectively, of our total revenue. In fiscal years 2015 and 2014, our four largest customers generated approximately 44% and 45%, respectively, of our total revenue. 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 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 the recent industry downturn, many of our customers experienced the same financial and operational challenges that we did, and some of our customers filed for bankruptcy protection. Given the cyclical nature of the E&P industry, we, as well as 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 are take-or-pay arrangements with minimum purchase obligations. During the industry downturn, our minimum contractual commitments 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 proppant directly from vendors, reducing our need for proppant. If market conditions do not continue to improve, or our customers buy 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 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 natural resources, clean air, drinking water, wetlands, endangered species, greenhouse gases, nonattainment areas, the environment, health and safety, 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.
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 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.
We continue to assess the impact of the recently enacted Tax Cuts and Jobs Act (the “new tax law”) as well as any future regulations implementing the new tax law and any interpretations of the new tax law. The effect of those regulations and
interpretations, as well as any additional tax reform legislation in the United States or elsewhere, could adversely affect our business and financial condition.
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 projects publishing a Notice of Proposed Rulemaking by June 2018, which would describe a proposed mechanism-regulatory, voluntary or a combination of both-to collect data on hydraulic fracturing chemical substances and mixtures. 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 plans. The EPA is also conducting a study of private wastewater treatment facilities (also known as centralized waste treatment (“CWT”) facilities) accepting oil and natural gas extraction wastewater. The EPA is collecting 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 Safe Drinking Water Act (“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, the Bureau of Land Management (“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.
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 announced intentions to publish reconsidered proposed New Source Performance Standards by August of 2018 with 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. 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 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 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 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 $79.1 million, $10.3 million and $64.0 million, respectively, in 2015, 2016 and 2017. 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 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 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.
In February 2016, our joint venture with the Sinopec Group (“Sinopec”), commenced 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 and any further international expansion 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, and bureaucratic delays. These may increase our costs and distract key personnel, which may adversely affect our business, financial condition or results of operations.
Our ability to utilize our net operating loss carryforwards and certain tax amortization deductions may be delayed or limited.
As of December 31, 2017, we had federal and state net operating loss carryforwards (“NOLs”), of approximately $1,600 million and $618 million, respectively, which if not utilized will begin to expire starting in 2032 for federal purposes and 2018 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 2017 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 February 22, 2018, we had $785.0 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.
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 was adversely affected by the industry downturn due to the 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 38.1%, 20.1% and 11.1%, respectively, of our common stock. As a result, Maju, Chesapeake and Senja, together, exercise 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. See “Certain Relationships and Related Transactions, and Director Independence -Investors’ Rights Agreements” in Item 13 of this annual report. 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. See “Certain Relationships and Related Transactions, and Director Independence -Investors’ Rights Agreements” in Item 13 of this annual report. 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” in Item 1A of this annual report.
An active liquid trading market for our common stock may not develop and our stock price may be volatile.
An active and liquid trading market for our common stock may not develop or be maintained. Liquid and active trading markets usually result in less price volatility and more efficiency in carrying out investors’ purchase and sale orders. 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;
· changes in revenue or earnings estimates or publication of reports by equity research analysts;
· speculation in the press or investment community;
· sales of our common stock by us or our stockholders, or the perception that such sales may occur;
· general market conditions, including fluctuations in actual and anticipated future commodity prices; 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.
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);
· establish new 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
· establish 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, 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 will be 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 will be 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. We are currently evaluating our existing controls against the standards adopted by the Committee of Sponsoring Organizations of the Treadway Commission. During the course of our ongoing evaluation and integration of the internal control over financial reporting, 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 additional administrative and accounting personnel to conduct our financial reporting. 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 procedures, certification and attestation requirements of Section 404 or that we or our auditors will not identify material weaknesses in internal control over financial reporting. 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. See “Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities - Dividends” in Item 5 of this annual report.
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. 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.
Item 1B. Unresolved Staff Comments
None.
Item 2.
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, 2017.
Hydraulic Fracturing District Offices
Currently, we have five district offices out of which we conduct hydraulic fracturing services. The following table provides certain information about our district office locations. 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, 2017.
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 have four district offices out of which we conduct wireline services. 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, 2017.
(1) Leased Facility
(2) In February 2018, the district office in Odessa, Texas was consolidated with the hydraulic fracturing district office in Odessa, Texas.
Manufacturing 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 a 89,522 square foot facility owned by us in Fort Worth, Texas.
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.
Principal Executive Offices
We maintain principal executive offices in Fort Worth, Texas. As of December 31, 2017 we leased approximately 90,000-square feet. In January 2018, we restructured our lease and reduced the amount of space to approximately 33,000-square feet.
Sales Offices
We have four sales offices, which we lease in Houston and Midland, Texas, Oklahoma City, Oklahoma, and Canonsburg, Pennsylvania.
Item 3.
Item 3. Legal Proceedings
We are involved in various legal proceedings from time to time in the ordinary course of our business. However, we are not currently involved in any legal proceedings that we believe are likely to have a material adverse effect on our operations or financial condition.
Item 4.
Item 4. Mine Safety Disclosures
Not applicable.
PART II
Item 5.
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Stockholder Information
On March 7, 2018, we had 109,274,564 shares of common stock outstanding held by a total of approximately 25 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 began trading on the New York Stock Exchange (the “NYSE”) under the ticker symbol “FTSI” on February 2, 2018 in connection with our IPO. Prior to that time, there was no established public trading market for our common stock. As a result, we have not set forth quarterly information with respect to the high and low prices for our common stock for the two most recent fiscal years. On March 7, 2018, the closing price of our common stock on NYSE was $19.61 per share. The following table sets forth for the period indicated the high and low sale prices per share for our common stock as reported on the NYSE for the period indicated:
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. Any decision to pay future cash dividends will depend upon various factors, including our results of operations, financial condition, capital requirements, contractual restrictions with respect to the payment of dividends, investment opportunities and other factors that our board of directors may deem relevant. Our Term Loan, Credit Facility and indenture governing our 2022 Notes contain restrictions and any future agreements may contain restrictions on our ability to pay dividends or make any other distribution or payment on account of our common stock.
Securities Authorized for Issuance Under Equity Compensation Plans
See Item 12. “Equity Compensation Plan Information” for information regarding securities authorized for issuance under equity compensation plans.
Unregistered Sales of Equity Securities
During the year ended December 31, 2017, there were no unregistered sales of our equity securities.
Issuer Purchases of Equity Securities
During the year ended December 31, 2017, there were no repurchases of our common shares.
Use of Proceeds from Registered Securities
On February 6, 2018, we closed our IPO of 19,500,000 shares of our common stock, and on February 8, 2018 we closed on an additional 2,925,000 shares of our common stock pursuant to the full exercise by the underwriters of an option to purchase additional shares, at a public offering price of $18.00 per share, for an aggregate offering of approximately $404 million, including shares sold by a selling stockholder. The offer and sale of all of the shares in the offering were registered under the Securities Act pursuant to a registration statement on Form S-1 (File No. 333-215998), which was declared effective by the SEC on February 1, 2018. Credit Suisse Securities (USA) LLC and Morgan Stanley & Co. LLC acted as representatives of the underwriters. The offering commenced on February 1, 2018 and did not terminate until the sale of all of the shares offered.
We received aggregate net proceeds from the offering of $303 million, after deducting underwriting discounts and commissions and other estimated offering expenses payable by us. None of the underwriting discounts and commissions or other offering expenses were incurred or paid to directors or officers of ours or their associates or to persons owning 10% or more of our common stock or to any affiliates of ours.
Because the closing of our IPO occurred on February 6, 2018, as of December 31, 2017, we had not yet received the net proceeds from the sale of shares of common stock in our IPO and, therefore, had used none of the proceeds as of December 31, 2017. There has been no material change in our planned use of the net proceeds from the offering as described in our final prospectus filed with the SEC pursuant to Rule 424(b) under the Securities Act.
Item 6.
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.
(1) We recorded depletion of $4.2 million in 2013 related to our sand mines before selling those assets in the third quarter of 2013.
(2) In 2013, this amount includes a goodwill impairment of $1,047.5 million and an asset impairment of $94.0 million related to the sale of our sand mining, processing and logistics assets. In 2014, this amount related to non-essential equipment and real property we identified to sell. For a discussion of amounts recorded for the three years ended December 31, 2017, see Note 9 - “Impairments and Other Charges” in Notes to our Consolidated Financial Statements included elsewhere in this annual report on Form 10-K.
(3) In 2013, this amount includes a loss of $289.7 million related to the sale of our sand mining, processing and logistics assets.
(4) 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.
(5) Net loss attributable to common stockholders is calculated by subtracting an 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, $115.9 million in 2014, and $92.8 million in 2013. For more information about the convertible preferred stock accretion, see note 7 below, Note 6 - “Convertible Preferred Stock” and Note 15 - “Earnings (Loss) Per Share” in Notes to our Consolidated Financial Statements included elsewhere in this annual report on Form 10-K.
(6) 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 15 - “Earnings (Loss) Per Share” and Note 17 - “Subsequent Events” in Notes to our Consolidated Financial Statements included elsewhere in this annual report on Form 10-K for more information.
(7) The holders of the convertible preferred stock are 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 have presented the convertible preferred stock as temporary equity but have not reflected any accretion of the convertible preferred stock in this table or in our Consolidated Financial Statements. See Note 6 - “Convertible Preferred Stock” and Note 15 - “Earnings (Loss) Per Share” in Notes to our Consolidated Financial Statements included elsewhere in this annual report on Form 10-K for more information. At December 31, 2017, the liquidation preference of the convertible preferred stock was estimated to be $1,132.7 million.
(8) 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:
(a) In 2013, these costs related to the sale of our proppant assets.
(b) For the year ended December 31, 2016, Adjusted EBITDA has not been adjusted to exclude the following items: employee severance costs of $0.8 million, supply commitment charges of $2.5 million and lease abandonment charges of $2.0 million. For the year ended December 31, 2015, Adjusted EBITDA has not been adjusted to exclude the following items: employee severance costs of $13.1 million, supply commitment charges of $11.0 million, significant legal costs of $8.1 million, lease abandonment charges of $1.8 million, and profit of $2.4 million from the sale of equipment to our joint venture affiliate.
(9) 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.
Item 7.
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 E&P, companies in shale and other unconventional resource formations. Our customers include Chesapeake Energy Corporation, ConocoPhillips, Devon Energy Corporation, EOG Resources, Inc., Diamondback Energy, Inc., EQT Company, Range Resources Corporation, and other leading E&P companies that specialize in unconventional oil and natural gas resources in North America. We are one of the top three hydraulic fracturing providers across our operating footprint, which consists of 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. Substantially all of our business activities support our well completion services. We manage our business, allocate resources, and assess our financial performance on a consolidated basis; therefore we do not have separate operating segments.
Significant developments in 2017 and 2018
· During the first quarter of 2017, we reached a milestone of over 10 million man-hours without a lost time incident, which is significantly better than our industry peer group, according to the U.S. Bureau of Labor Statistics.
· Due to improving industry conditions and our operational efficiencies, during 2017, we generated positive operating income for the first time since 2014 and positive net income for the first time since 2011.
· During 2017, we activated ten fleets in response to increased customer demand, which brought our total active fleet count to 27 at December 31, 2017.
· During the fourth quarter of 2017, we purchased certain components that can be used to build two additional fleets, which we expect to complete in 2018. Once completed, our total available fleet size will increase from 32 fleets to 34 fleets, representing a total of 1.7 million hydraulic horsepower. We expect the total cost of these two additional fleets to be approximately $50 million.
· 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 approximately $303 million, and we intend to use the net proceeds from the offering for general corporate purposes, including debt repayments.
· In January and February 2018, we repaid $345.0 million of aggregate principal amount of long-term debt using cash on hand and proceeds received from the IPO. Our remaining principal amount of long-term debt after these repayments was $785.0 million as of February 22, 2018.
· In February 2018, we entered into a $250 million asset-based revolving credit facility.
Trends that affected our business from 2015 to 2017
Our business is cyclical, and we depend on the willingness of our customers to make expenditures to explore for, develop, and produce oil and natural gas in the United States. The willingness of our customers to undertake these activities is predominantly influenced by current and expected future prices for oil and natural gas.
Oil and natural gas prices declined significantly in 2015. As a result of these low commodity prices, our customers significantly reduced their hydraulic fracturing activities in 2015. This reduction in activity levels created an oversupply of service providers in our industry and, consequently, market prices for our services declined significantly.
In early 2016, we continued to experience very low commodity prices; however, oil and natural gas prices started improving in the second quarter of 2016 and generally increased through the remainder of 2016. The low commodity prices at the beginning of 2016 caused our customers to reduce their activity levels and request lower pricing for our services. As commodity prices improved, we experienced an increase in demand for our services in the second half of 2016. This increase in activity combined with a lower
level of available hydraulic fracturing equipment in the market allowed us to request increased pricing for our services. Many of our customers agreed to price increases that took effect in the first quarter of 2017.
In 2017, higher commodity prices enabled our customers to significantly increase their activity levels, which resulted in an increase in the horizontal rig count from 532 at the end of 2016 to 796 at the end of 2017, according to a report by Baker Hughes, Inc. This increase in customer activity levels increased the demand for hydraulic fracturing services above the available supply. As a result, our customers agreed to price increases in 2017, and we activated additional idle fleets to meet this demand.
Business outlook
We anticipate that customer activity levels will remain strong into 2018, which should provide us an opportunity to activate additional fleets at favorable operating margins. We are also focused on minimizing cost inflation in this environment to optimize our operating margins.
Results of Operations
Revenue
We recognize revenue upon the completion of a stage of a job. A stage is considered complete when we have met the specifications set forth by our customer. We typically complete multiple stages per day during the course of a job. Invoices typically include an equipment charge and material charges for proppant, chemicals and other products consumed during the course of providing our services. See “Business - Our Services - Hydraulic Fracturing” in Item 1 of this annual report for details regarding fracturing stages and fleets and the types of agreements we use to provide hydraulic fracturing services. The following table includes certain operating statistics that affect our revenue:
(1) Active fleets is the average number of fleets operating during the period. We had 27, 17 and 14 active fleets at December 31, 2017, 2016 and 2015, respectively.
(2) Total fleets is the total number of fleets owned during the period.
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 average number of active fleets during 2017 increased by 7.7 from 2016, due to increased customer demand. At December 31, 2017, 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. We believe all of our remaining inactive fleets can be returned to active service within six months, if market conditions require. We estimated the total cost to reactivate all of our inactive fleets, as of December 31, 2017, would be approximately $34 million, including capital expenditures, repairs charged as operating expense, labor costs, and other operating expenses.
The increase in revenue from related parties in 2017 were due to increases in the activity levels for Chesapeake.
Total revenue in 2016 decreased by $843.1 million from 2015. This decrease was due to a lower pricing environment for both our services and fracturing materials in 2016, lower customer activity and well completion levels in 2016, resulting in fewer stages completed, and certain customers choosing to procure their own proppants in 2016.
We began extending price concessions to our customers in the first quarter of 2015 as a result of the decline in oil and gas commodity prices that began in 2014. Our customers significantly reduced their hydraulic fracturing activities in response to the lower commodity price environment. This reduction in activity levels created an oversupply of service providers in our industry and,
consequently, market prices for our services declined significantly. In response to the lower pricing environment and lower customer activity levels, we reduced the number of fleets operating during 2016 by an average of 7.4 fleets. However, in 2016 we improved our ability to operate our active fleets with less downtime which increased the number of stages we completed per average active fleet.
The decrease in revenue from related parties in 2016 was due to a decrease in the activity levels 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:
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 replace 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 have become comprised of refurbished assets in recent years, our depreciation has 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.
Total costs of revenue in 2016 decreased by $800.8 million from 2015. This decrease was primarily due to a decrease in our costs of revenue, excluding depreciation, and a decrease in the depreciation expense for our service equipment.
Costs of revenue, excluding depreciation, in 2016 decreased by $747.4 million from 2015. This decrease was due to our lower number of active fleets during 2016 in response to lower customer activity and well completion levels; lower prices for materials used in the fracturing process in 2016; the effect of our cost reduction initiatives in 2016, which resulted in significant savings in labor and repair costs; and changes in customer job requirements in 2016.
Depreciation for our service equipment in 2016 decreased by $53.4 million from 2015. This decrease was the result of asset impairments, asset disposals and certain assets becoming fully depreciated. Additionally, in recent years we have chosen to refurbish our equipment as it approaches the end of its useful life, rather than to replace it by purchasing new equipment. The cost of refurbishing our equipment is significantly lower than it would be to purchase new equipment. As more of our fleet has become comprised of refurbished assets in recent years, our depreciation has correspondingly declined.
Total costs of revenue as a percentage of total revenue increased by 12.0 percentage points from 102.5% in 2015 to 114.5% in 2016. This change was primarily due to increased price concessions we extended to our customers in 2016, which have been partially offset by a lower number of active fleets in 2016, lower material costs; and our cost reduction initiatives. Our total costs of
revenue exceeded our total revenue during these periods primarily due to the price concessions we have extended to our customers during these periods.
Selling, general and administrative expense
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.
Selling, general and administrative expense in 2016 decreased by $90.3 million from 2015. Approximately $60 million of this decrease was related to a decrease in employee headcount in connection with the downturn in our business. Approximately $10 million of this decrease was due to lower legal costs. The remaining decrease was primarily the result of our various cost saving initiatives.
Depreciation and amortization
The following table summarizes our depreciation and amortization:
(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.
(3) Related to definite-lived intangible assets that were written down to zero during the year ended December 31, 2015.
Depreciation and amortization in 2017 decreased by $26.0 from 2016. This decrease was primarily due to a decrease in depreciation for our service equipment, which has been previously discussed. The remaining decrease was primarily due to asset disposals and certain assets becoming fully depreciated.
Depreciation and amortization in 2016 decreased by $159.8 million from 2015. This decrease was primarily due to the cessation of amortization associated with the intangible assets that were impaired during the year ended December 31, 2015, and the decrease in depreciation for our service equipment which has been previously discussed. The remaining decrease was primarily due to asset disposals and certain assets becoming fully depreciated.
Impairments and other charges
The following table summarizes our impairments and other charges:
Impairment of Assets and Goodwill: 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. During the first nine months of 2015, we recorded a non-cash
goodwill impairment of $7.1 million for our wireline reporting unit and an asset impairment of $0.5 million related to real property that we no longer use.
In the fourth quarter of 2015, we concluded that the persistent low commodity price environment and its effect on our current and forecasted cash flows required us to perform multiple asset impairment tests. As a result, we recorded a number of asset impairments in the fourth quarter of 2015.
· We evaluated the long-lived assets of our pressure pumping asset group for impairment and concluded that the fair value of this asset group was lower than the carrying value of the assets in the asset group. We recognized a total impairment for this asset group of $487.0 million. Of this amount, $461.4 million was attributable to our customer relationships, $20.6 million was attributable to certain equipment, and $5.0 million was attributable to our proprietary chemical blends.
· We evaluated the long-lived assets of our wireline asset group for impairment and concluded that the fair value of this asset group was lower than the carrying value of the assets in the asset group. We recognized a total impairment for this asset group of $33.3 million. Of this amount $24.2 million was attributable to certain equipment and $9.1 million was attributable to our customer relationships.
· We evaluated our tradename intangible asset for impairment and concluded that the fair value of this asset was lower than its carrying value, which resulted in an impairment of $30.2 million.
· We recorded $14.8 million of impairments for certain land and buildings that we no longer use.
Supply Commitment Charges: We have recorded supply commitment charges related to contractual inventory purchase commitments to certain proppant suppliers. In 2017, 2016 and 2015, we recorded charges under these supply arrangements of $1.2 million, $2.5 million and $11.0 million, respectively. These charges were attributable to our decreased volume of purchases from these suppliers due to our lower activity levels and/or certain customers procuring their own proppants.
While we have successfully worked with our vendors to minimize charges related to these purchase commitments, if industry conditions worsen, if customer requirements for specific types of proppant differ from our contracted supply, or if we are unable to work with our vendors in the future, we may incur supply commitment charges in future periods.
Lease Abandonment Charges: During 2016 and 2015, we vacated certain leased facilities to consolidate our operations. In 2017, 2016 and 2015, we recognized expense of $0.6 million, $2.0 million and $1.8 million, respectively, in connection with these actions.
Employee Severance Costs: During 2016 and 2015, we incurred employee severance costs of $0.8 million and $13.1 million, respectively, in connection with our corporate and operating restructuring initiatives. At December 31, 2016, we had paid substantially all severance payments owed to former employees.
Inventory Write-down: During 2015, we made improvements to our supply chain that reduced our inventory requirements. In connection with this initiative we executed a program to liquidate excess inventory. We recorded a $24.5 million inventory write-down charge in connection with this liquidation program.
Acquisition earn-out adjustments: In 2015, we remeasured the fair value of the contingent consideration related to a wireline acquisition and we recorded adjustments to reduce this liability by $3.4 million. At December 31, 2015 and December 31, 2016, the fair value of the contingent consideration was zero and the period to earn the contingent consideration expired on October 31, 2016.
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 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 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.
Interest expense, net of interest income, in 2016 increased by $10.3 million from 2015. The increase was due to a higher average long-term debt balance and a higher average interest rate in 2016 for our senior floating rate notes due June 2020.
Gain on extinguishment of debt, net
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 $1.6 million in 2017. This amount consisted of state margin taxes accounted for as income taxes. 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 state income tax expense or benefit related to our income or losses in 2017, 2016 or 2015. See Note 12 - “Income Taxes” in Notes to our Audited Consolidated Financial Statements included elsewhere in this annual report on Form 10-K for more information regarding our income taxes and valuation allowance.
Liquidity and Capital Resources
Sources of Liquidity
At December 31, 2017, we had $208.1 million of cash, which represented our total liquidity position. We believe that our cash and cash provided by operations will be sufficient to fund our operations and capital expenditures.
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. In an event of default or if the amount available under the 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 17 - “Subsequent Events” in Notes to our Audited Consolidated Financial Statements included elsewhere in this annual report on Form 10-K for more information on our new credit facility.
Cash Flows
The following table summarizes our cash flows:
Cash flows from operating activities have historically been a significant source of liquidity we use to fund capital expenditures and repay our debt. Changes in cash flows from operating activities are primarily affected by the same factors that affect our net income, excluding non-cash items such as depreciation and amortization, stock-based compensation, and impairments of assets.
Cash flows from operating activities: Net cash provided by operating activities was $180.0 million in 2017 compared to net cash used in operating activities of $109.8 million in 2016. Cash flows from operating activities consists of net income or loss adjusted for non-cash items and changes in operating assets and liabilities. Net income or loss adjusted for non-cash items resulted in a cash increase of $288.8 million and a cash decrease of $130.9 million in 2017 and 2016, respectively. This change was primarily due to higher earnings in 2017. The net change in operating assets and liabilities resulted in a cash decrease of $108.8 million and a cash increase of $21.1 million 2017 and 2016, respectively. The net change in operating assets and liabilities for 2017 was primarily due to an increase in working capital resulting from our increased activity level.
Net cash used in operating activities was $109.8 million in 2016 compared to net cash provided by operating activities of $50.6 million in 2015. Net loss adjusted for non-cash items resulted in a cash decrease of $130.9 million and $133.3 million in 2016 and 2015, respectively. The net change in operating assets and liabilities resulted in a cash increase of $21.1 million and $183.9 million in 2016 and 2015, respectively. The net change in operating assets and liabilities in 2016 was primarily due to decreased accounts receivable and inventories, partially offset by decreased accrued expenses, which were all due to our lower activity levels in 2016.
Cash flows from investing activities: Net cash used in investing activities was $54.6 million in 2017 compared to cash provided by investing activities of $43.1 million in 2016. This change was primarily due to increased capital expenditures in 2017, decreased asset disposal proceeds in 2017 and decreased insurance recovery proceeds received in 2017. The increase in capital expenditures in 2017 was due to our increased operations and fleet reactivations in 2017 as well as an approximate $10 million purchase of certain asset components that we plan to use to build two additional fleets in 2018.
Net cash provided by investing activities in 2016 was $43.1 million compared to net cash used in investing activities of $97.9 million in 2015. This change was primarily due to reduced capital expenditures in 2016, increased asset disposal proceeds in 2016, and insurance recovery proceeds received in 2016.
Cash flows from financing activities: Net cash used in financing activities was $77.6 million and $37.6 million in 2017 and 2016, respectively, which was comprised of debt repayments.
Net cash provided by financing activities was $301.4 million in 2015. This net cash flow was due to the issuance of $350 million aggregate principal amount of our senior floating rate notes due June 2020, which was partially offset by a repayment of borrowings under our previously existing revolving credit facility.
Cash Requirements
Contractual Commitments and Obligations
The following table summarizes our contractual commitments and obligations at December 31, 2017:
(1) Our Term Loan bears interest at a variable rate based on LIBOR plus a margin of 4.75% per annum, but never less than 5.75% per annum due to a 1.00% LIBOR floor. The future interest payment amounts included in the table for these notes have been calculated at the rate in effect at December 31, 2017.
(2) Our senior floating rate notes due June 2020 bear interest at a variable rate based on LIBOR plus a margin of 7.5% per annum. The future interest payment amounts included in the table for these notes have been calculated at the rate in effect at December 31, 2017.
In 2017, we repaid $77.3 million of aggregate principal amount of long-term debt. We recognized a corresponding loss on debt extinguishment of $1.4 million. See Note 5 - “Debt” in Notes to our Audited Consolidated Financial Statements included elsewhere in this annual report on Form 10-K for more information on our long-term debt obligations.
In February 2018 the Company completed an IPO of its common stock and used proceeds from the offering and cash on hand to repay certain long-term debt. See Note 17 - “Subsequent Events” in Notes to our Audited Consolidated Financial Statements included elsewhere in this annual report on Form 10-K for more information. The following table summarizes our contractual commitments and obligations after giving effect to these debt repayments in 2018:
(1) Our Term Loan bears interest at a variable rate based on LIBOR plus a margin of 4.75% per annum, but never less than 5.75% per annum due to a 1.00% LIBOR floor. The future interest payment amounts included in the table for these notes have been calculated at the rate in effect at January 31, 2018.
Capital Expenditures
The nature of our capital expenditures consists of a base level of investment required to support our current operations and amounts related to growth and company initiatives. Our capital expenditures for 2017 represented the amount necessary to support our current operations and fleet reactivations. We estimate capital expenditures in 2018 will range from $130 million to $150 million. During the fourth quarter of 2017, we purchased certain components that can be used to build two additional fleets, which we expect to complete in 2018. Once completed, our total available fleet size will increase from 32 fleets to 34 fleets, representing a total of 1.7 million hydraulic horsepower. We expect our capital expenditures related to these two additional fleets to be approximately $50 million, of which approximately $10 million was spent in 2017 and the remainder will be spent in 2018. Our remaining estimate for capital expenditures will be used to support our current operations and fleet reactivations in 2018. Our cash and any cash provided by operations will be used to fund our capital expenditure needs, which we believe will be sufficient to support our operations in 2018. We continuously evaluate our capital expenditures and the amount we ultimately spend will primarily depend on industry conditions.
Off-Balance Sheet Arrangements
Except for our normal operating leases, we do not have any off-balance sheet financing arrangements, transactions, or special purpose entities.
Critical Accounting Estimates
The preparation of our consolidated financial statements and related notes requires us to make estimates that affect the reported amounts of assets, liabilities, revenue and expenses, and related disclosures of contingent assets and liabilities. We base these estimates on historical results and various other assumptions believed to be reasonable, all of which form the basis for making estimates concerning the carrying values of assets and liabilities that are not readily available from other sources. Actual results may differ from these estimates.
In the notes accompanying the consolidated financial statements included elsewhere in this annual report on Form 10-K, we describe the significant accounting policies used in the preparation of our consolidated financial statements. We believe that the following represent the most significant estimates and management judgments used in preparing the consolidated financial statements.
Property, Plant, and Equipment
We calculate depreciation based on the estimated useful lives of our assets. When assets are placed into service, we make estimates with respect to their useful lives that we believe are reasonable. However, the cyclical nature of our business, which results in fluctuations in the use of our equipment and the environments in which we operate, could cause us to change our estimates, thus affecting the future calculation of depreciation.
We continuously perform repair and maintenance expenditures on our service equipment. Expenditures for renewals and betterments that extend the lives of our service equipment, which may include the replacement of significant components of service equipment, are capitalized and depreciated. Other repairs and maintenance costs are expensed as incurred. The determination of whether an expenditure should be capitalized or expensed requires management judgment with regard to the effect of the expenditure on the useful life of the equipment.
We separately identify and account for certain significant components of our hydraulic fracturing units including the engine, transmission, and pump, which requires us to separately estimate the useful lives of these components.
Definite-lived Intangible Assets
The amortization of our definite-lived intangible assets reflected in our consolidated statements of operations was $102.5 million for the year ended December 31, 2015. These intangible assets were primarily related to customer relationships and proprietary chemical blends acquired in business acquisitions. We calculated amortization for these assets based on their estimated useful lives. When these assets were recorded, we made estimates with respect to their useful lives that we believed were reasonable. However, these estimates contained judgments regarding the future utility of these assets and a change in our assessment of the useful lives of these assets could have materially changed the future calculation of amortization. At December 31, 2015, we impaired all of our definite-lived intangible assets.
Impairment of Long-Lived Assets, Goodwill and Other Intangible Assets
Long-lived assets, such as property, plant, equipment and definite-lived intangible assets, are reviewed for impairment when events or changes in circumstances indicate that the carrying amount may not be recoverable, such as insufficient cash flows or plans to dispose of or sell long-lived assets before the end of their previously estimated useful lives. If the carrying amount is not recoverable, we recognize an impairment loss equal to the amount by which the carrying amount exceeds fair value. We estimate fair value based on the income, market or cost valuation techniques. Our fair value calculations for long-lived assets and intangible assets contain uncertainties because they require us to apply judgment and estimates concerning future cash flows, strategic plans, useful lives and assumptions about market performance. We also apply judgment in the selection of a discount rate that reflects the risk inherent in our current business model.
We have historically acquired goodwill and indefinite-lived intangible assets related to business acquisitions. Goodwill represents the excess of the purchase price over the fair value of net assets acquired. We review our goodwill and indefinite-lived intangible assets on an annual basis, at the beginning of the fourth quarter, and whenever events or changes in circumstances indicate the carrying value of goodwill or an intangible asset may exceed its fair value. If the carrying value of goodwill or an intangible asset exceeds its fair value, we recognize an impairment loss for this difference. Our impairment loss calculations for goodwill and indefinite-lived intangible assets contain uncertainties because they require us to estimate fair values of our reporting units and intangible assets, respectively. We estimate fair values based on various valuation techniques such as discounted cash flows and comparable market analyses. These types of analyses contain uncertainties because they require us to make judgments and assumptions regarding future profitability, industry factors, planned strategic initiatives, discount rates and other factors.
Unconditional Purchase Obligations
We have historically entered into supply arrangements, primarily for sand, with our vendors that contain unconditional purchase obligations. These represent obligations to transfer funds in the future for fixed or minimum quantities of goods or services at fixed or minimum prices, such as “take-or-pay” contracts. We enter into these unconditional purchase obligation arrangements in the normal course of business to ensure that adequate levels of sourced product are available to us. To account for these arrangements, we must monitor whether we may be required to make a minimum payment to a vendor in a future period because our projected inventory purchases may not satisfy our minimum commitments. If we conclude that it is probable that we will make a minimum payment under these arrangements, we will record an estimated loss for these commitments in the current period.
A loss related to an unconditional purchase obligation contains uncertainties because it requires us to make assumptions and apply judgment to forecast future demand, determine the ultimate allocation of a commitment shortfall to our various vendors, and
assess our ability to cure a commitment shortfall during cure periods allowed for by certain vendors. Although we believe that our judgments and estimates are reasonable, actual results could differ, and we may be subject to additional losses or gains that could be material in future periods.
Income Taxes
Income taxes are accounted for using the asset and liability method. Deferred taxes are recognized for the tax consequences of temporary differences by applying enacted statutory tax rates applicable to future years to differences between the financial statement carrying amounts and the tax bases of existing assets and liabilities. We recognize future tax benefits to the extent that such benefits are more likely than not to be realized.
We record a valuation allowance to reduce the value of a deferred tax asset if based on the consideration of all available evidence, it is more likely than not that all or some portion of the deferred tax asset will not be realized. Significant weight is given to evidence that can be objectively verified. We evaluate our deferred income taxes at each reporting date to determine if a valuation allowance is required by considering all available evidence, including historical and projected taxable income and tax planning strategies. We will adjust a previously established valuation allowance if we change our assessment of the amount of deferred income tax asset that is more likely than not to be realized.
An estimate of whether a valuation allowance is necessary and the related amount of the valuation allowance contain uncertainties because it requires us to apply judgment to all positive and negative evidence available to us. When considering the likelihood of whether a deferred tax asset will be available to offset future taxable income, we assess, among other things, our historical and projected taxable income or loss. When performing this assessment, we must consider the cyclical nature of our business. Our business is heavily influenced by current and expected prices for oil and natural gas. These prices are outside of our control and a downturn in the market can result in periods of significant taxable losses for us, which could prevent the realization of a deferred tax asset. We therefore must consider the future possibility of an industry downturn and the severity of its effect on our business when considering all positive and negative evidence related to the realization of our deferred tax assets. Although we believe that our judgments and estimates are reasonable, an adjustment to a valuation allowance in a current period may require a material adjustment in a future period if our assumptions regarding our future taxable income are proven inaccurate due to an industry downturn.
Tax Contingencies
We are subject to income taxes and other state and local taxes. Our tax returns are periodically audited by federal, state and local tax authorities. These audits include questions regarding our tax filing positions, including the timing and amount of deductions and the reporting of various taxable transactions. At any one time, multiple tax years are subject to audit by the various tax authorities. After evaluating the exposures associated with our various tax filing positions, we may record a liability for such exposures. A number of years may elapse before a particular matter, for which we have established a liability, is audited and fully resolved or clarified. We adjust our liability for these tax exposures in the period in which a tax position is effectively settled, the period in which the statute of limitations expires for the relevant taxing authority to examine the tax position, or when more information becomes available.
Our liabilities for these tax positions contain uncertainties because management is required to make assumptions and apply judgment to estimate the exposures associated with our various filing positions. Although we believe that our judgments and estimates are reasonable, actual results could differ, and we may be subject to losses or gains that could be material.
Recent Accounting Pronouncements
See Note 2 - “Summary of Significant Accounting Policies” in Notes to our Consolidated Financial Statements included elsewhere in this annual report on Form 10-K for more information.
Item 7A.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
At December 31, 2017, we held no derivative instruments that materially increased our exposure to market risks for interest rates, foreign currency rates, commodity prices or other market price risks.
We are subject to interest rate risk on a portion of our long-term debt. Our Term Loan bears interest at a variable rate based on LIBOR plus a margin of 4.75% per annum, with a 1.00% LIBOR floor. As of December 31, 2017, LIBOR was above the 1.00% floor. Therefore a 1.00% increase in LIBOR would increase the annual interest payments for this debt by approximately $4.2 million.
Our senior floating rate notes due June 2020 bear interest at a variable rate based on LIBOR plus a margin of 7.50% per annum. Therefore, a 1.00% increase in LIBOR would increase the annual interest payments for these notes by approximately $3.0 million. The senior floating rate notes were redeemed in full on February 22, 2018 using proceeds received in connection with our IPO.
We are subject to commodity price risk related to our diesel fuel usage. A $0.25 per gallon change in the price of diesel fuel would have changed our costs of revenue, excluding depreciation, by approximately $6.5 million.
During 2017, substantially all of our operations were conducted within the United States; therefore we had no significant exposure to foreign currency exchange rate risk.
Item 8.
Item 8. Financial Statements and Supplementary Data
The information required by this Item 8 is included in our Consolidated Financial Statements and the notes thereto beginning on page in this annual report on Form 10-K.
Item 9.
Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure
None.
Item 9A.
Item 9A. Controls and Procedures
Evaluation of Disclosure Controls and Procedures
As required by Rule 13a-15(b) and Rule 15d-15(b) under the Exchange Act, our management, including our Chief Executive Officer and Chief Financial Officer, evaluated, as of December 31, 2017, the effectiveness of our disclosure controls and procedures as defined in Exchange Act Rule 13a-15(e) and Rule 15d-15(e). Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of December 31, 2017, to provide reasonable assurance that information required to be disclosed by us in reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified by the rules and forms of the Exchange Act and is accumulated and communicated to management, including the Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosures.
We believe, however, that a controls system, no matter how well designed and operated, cannot provide absolute assurance that the objectives of the controls systems are met, and no evaluation of controls can provide absolute assurance that all control issues and instances of fraud or error, if any, within a company have been detected.
Management’s Annual Report on Internal Control over Financial Reporting & Attestation Report of the Independent Public Account Firm
This annual report on Form 10-K does not include a report of management’s assessment regarding internal control over financial reporting or an attestation report of our registered public accounting firm due to a transition period established by rules of the SEC for newly public companies.
Changes in Internal Control over Financial Reporting
There has been no change in internal control over financial reporting that occurred during the quarter ended December 31, 2017 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
Item 9B.
Item 9B. Other Information
None.
PART III
Item 10.
Item 10. Directors, Executive Officers and Corporate Governance
Directors and Executive Officers.
The executive officers and directors are listed below with a description of their experience and certain other information.
* Age as of March 7, 2018.
(1) Member of the audit committee.
(2) Member of the compensation committee.
(3) Member of the nominating and corporate governance committee.
Michael J. Doss was elected as a director of the Company immediately following effectiveness of the Company’s registration statement on February 1, 2018. He has served as the Company’s Chief Executive Officer since October 2015. He joined the Company in January 2014 as Senior Vice President-Finance and Treasurer and was named Chief Financial Officer in December 2014. From July 2008 until joining the Company, Mr. Doss served as Vice President of Finance of Energy Transfer Partners, L.P. (“ETP”), a master limited partnership that owns and operates a portfolio of energy assets in the United States and then as Vice President of Strategic Planning for its affiliate Energy Transfer Equity, L.P. Prior to ETP, he was a Senior Credit Officer at Moody’s Investors Service, a provider of credit ratings, research and risk analysis, covering a diverse portfolio of oil and natural gas issuers. Prior to that, Mr. Doss spent more than seven years of his career in public accounting at Ernst & Young LLP serving clients in the oil and natural gas industry. He earned a Bachelor of Business Administration and Master of Professional Accounting from the University of Texas at Austin. Mr. Doss also earned a Master of Business Administration from Columbia Business School.
Buddy Petersen has served as the Company Chief Operating Officer (“COO”), since October 2015. He joined the Company in June 2015 as Senior Vice President, Continuous Improvement and was named Senior Vice President of Operations and Wireline in August 2015. He has over 25 years of experience in the oil and natural gas industry. Prior to joining the Company, Mr. Petersen was COO of GoFrac LLC, an oil and natural gas stimulation company from October 2014 to June 2015, Vice President of Sales for Frac-Chem Inc., an oilfield chemical manufacturer and supplier and an affiliate of Koch Industries, from August 2013 to October 2014, President and COO of Compass Well Services LLC, a hydraulic fracturing and cementing services company from October 2010 to August 2013, and COO of Allied Cementing Co., a company providing cementing and acidizing services to the oil and natural gas industry from October 2007 to October 2010. Mr. Petersen spent 14 years working in various roles of increasing responsibility with Halliburton Energy Services (“Halliburton”), an oilfield services and products company. In April 2017, Mr. Petersen joined the board of directors of L.O. Transport, Inc., a company that provides transportation services to oil and gas producers. He earned a bachelor’s degree in civil engineering from New Mexico State University.
Lance Turner has served as the Company’s Chief Financial Officer and Treasurer since October 2015. He joined the Company in April 2014 as Director of Finance and was promoted to Vice President of Finance in January 2015. Prior to joining the Company, Mr. Turner spent approximately 11 years with Ernst & Young LLP, with the majority of that time in its transaction services group coordinating and advising clients on buy side and sell side transactions in various industries. He earned a Bachelor of Business
Administration and Master of Professional Accounting from the University of Texas at Austin and is a Certified Public Accountant in the state of Texas.
Karen D. Thornton has served as the Company’s Chief Administrative Officer since March 2017. Ms. Thornton previously served as the Company’s Vice President of Human Resources from the time she joined the Company in March 2014. Prior to joining the Company, she was an independent consultant at Alkat Consulting and served as the Strategic Human Capital Management Lead focusing on human resources and payroll application implementations for Darling Ingredients Inc., an Irving, Texas company providing a global growth platform for the development and production of sustainable natural ingredients, from June 2013 to March 2014. Prior to Alkat Consulting, Ms. Thornton served in various leadership positions, including the Vice President, Human Resources & Management Services for the Emergency Medical Services Corporation in Dallas, Texas, from 2001 to 2012. Ms. Thornton received her Bachelor of Science Industrial Management from Purdue University and her Master of Business Administration from The University of Texas at Austin’s Red McCombs School of Business.
Jennifer L. Keefe has served as the Company’s Senior Vice President, General Counsel and Chief Compliance Officer since March 2017. Ms. Keefe previously served as our Deputy General Counsel managing our Commercial Litigation, Employment Compliance and Risk Departments from the time she joined our Company in September 2014. Prior to joining our Company, she was a partner in the Dallas, Texas office of the international law firm of Squire Patton Boggs, where she joined in February 1997. Ms. Keefe received her Bachelor of Arts in Political Science and Spanish from Vanderbilt University and her Juris Doctor from Southern Methodist University Dedman School of Law. She is licensed to practice law in the state of Texas.
Perry A. Harris has served as the Company’s Senior Vice President, Commercial since July 2015. Mr. Harris joined the Company as Senior Vice President of Wireline Operations in December 2014 upon our acquisition of J-W Wireline Company, a case-hole wireline company. Prior to the acquisition, Mr. Harris was President of J-W Wireline Company from February 2012 to December 2014. He has more than 36 years of experience in the oil and natural gas industry, including over 24 years at Halliburton. At Halliburton, Mr. Harris held various leadership positions, including Northeast U.S. Area Operations Manager, Northeast U.S. Senior District Manager and Wireline Global Business Development, Marketing & Technology Manager. He earned a bachelor degree in mining engineering from West Virginia University.
Goh Yong Siang has served as a director of the Company since May 2011 and currently is Chairman of the board of directors. Mr. Goh is a board designee of Maju, an indirect wholly owned subsidiary of Temasek, an investment company based in Singapore and our largest stockholder. From July 2011 until his retirement in 2013, Mr. Goh served as the Head of Australia & New Zealand for Temasek. He served as Co-Head, Organization & Leadership for Temasek from April 2010 to July 2011 and Head of Strategic Relations for Temasek from August 2006 to April 2010. Prior to joining Temasek, Mr. Goh served as President of ST Engineering (USA). Mr. Goh provides significant insight to our board of directors, particularly as it relates to financial matters and business knowledge, from his many years of experience at Temasek and other private equity firms. Mr. Goh’s international expertise is also beneficial to our board of directors.
Domenic J. Dell’Osso, Jr. has served as a director of the Company since May 2011. He is a board designee of Chesapeake, an oil and natural gas producing company, and one of our largest stockholders. Currently, Mr. Dell’Osso is Executive Vice President and Chief Financial Officer of Chesapeake Parent, one of our customers, a position he has held since November 2010. Mr. Dell’Osso served as Vice President-Finance of Chesapeake Parent and Chief Financial Officer of Chesapeake Parent’s wholly owned subsidiary, Chesapeake Midstream Development, L.P., from August 2008 to November 2010. Prior to joining Chesapeake Parent, Mr. Dell’Osso was an energy investment banker with Jefferies & Co. from April 2006 to August 2008 and Banc of America Securities from 2004 to April 2006. Mr. Dell’Osso previously served as a director of the general partner of Chesapeake Midstream Partners from 2011 to 2014 and as a director of Chaparral Energy, Inc. from 2013 to 2014. Mr. Dell’Osso brings extensive financial and business expertise, as well as in-depth energy industry knowledge, to our board of directors from his service as Chief Financial Officer of Chesapeake Parent and from his background in investment banking.
Bryan J. Lemmerman has served as a director of the Company since February 2013. He is a board designee of Chesapeake. He is currently Vice President-Business Development at Chesapeake Parent, a position he has held since June 2015. He served as Vice President-Marketing at Chesapeake Parent from October 2014 to June 2015, Vice President-Strategic Planning at Chesapeake Parent from October 2013 to October 2014, Vice President-Finance at Chesapeake Parent from January 2012 to September 2013 and Director-Finance at Chesapeake Parent from May 2010 to December 2011. Mr. Lemmerman has served as a director of Sundrop Fuels, Inc. since 2012. Prior to joining Chesapeake Parent, Mr. Lemmerman served as a consultant to various oil and natural gas companies and private equity firms. Mr. Lemmerman was also a portfolio manager at hedge funds Highview Capital Management and Ritchie Capital Management. Mr. Lemmerman provides extensive energy industry and business development insight to our board of directors from his service at Chesapeake Parent and from his background as a consultant to hedge funds, family offices and private equity firms.
Ong Tiong Sin has served as a director of the Company since May 2011. Mr. Ong is a board designee of Senja, an investment company affiliated with RRJ and one of our largest stockholders. Mr. Ong is the founder, Chairman and Chief Executive Officer of RRJ, the general partner of RRJ Capital Master Fund I, L.P., a private equity fund established in March 2011 which focuses on private equity investments in China and Southeast Asia. From January 2008 to March 2011, Mr. Ong was Chief Executive Officer of Hopu Fund, a China-focused private equity fund. Previously, Mr. Ong had a 15-year career with Goldman, Sachs & Co., an investment banking, securities and investment management firm. Based in Beijing, he was a co-head of Goldman Sachs Asian Ex-Japan Investment Banking Division. Mr. Ong became a managing director in the corporate finance department of a subsidiary of Goldman Sachs in 1996 and a partner in 2000. Prior to his transfer to Beijing, Mr. Ong was the co-president of Goldman Sachs Singapore and had previously worked in investment banking divisions in Hong Kong and New York. Mr. Ong brings extensive financial and banking expertise to our board of directors, and his experience in private equity provides a great deal of knowledge with respect to investment in and operations of companies.
Boon Sim has served as a director of the Company since June 2013. Mr. Sim is a board designee of Maju. Since September 2017, he has served as the Managing Partner of Artius Capital Partners. He was previously Advisory Senior Director of Temasek from April 2016 to December 2017 and President, Americas Group, Head of Markets Group and Head of Credit and Life Science Portfolio at Temasek from June 2012 to April 2016. Prior to joining Temasek, Mr. Sim was the Global Head of Mergers & Acquisitions (“M&A”), at Credit Suisse, an investment banking, securities and investment management firm based in New York and a member of Credit Suisse Investment Bank’s Operating Committee. During a 20 year career at Credit Suisse and The First Boston Corporation, a predecessor company of Credit Suisse, Mr. Sim had held various management positions including Head of M&A Americas and Co-head of Technology Group. Prior to joining The First Boston Corporation, Mr. Sim was a design engineer at Texas Instruments Inc., a semiconductor design and manufacturing company, focusing on semiconductor design. Mr. Sim provides significant insight to our board of directors, particularly as it relates to financial matters and business knowledge, from his many years of experience at Temasek, Credit Suisse and The First Boston Corporation.
Carol J. Johnson was appointed as a director of the Company immediately following the effectiveness of our amended and restated certificate of incorporation and amended and restated bylaws on February 1, 2018. She served as President and Chief Operating Officer of AlliedBarton Security Services, LLC, a manned guarding physical security company, from 2014 to 2016. From 2011 to 2013, Ms. Johnson served as Senior Vice President, Client Experience at AlliedBarton Security Services. Ms. Johnson has served on the board of directors of The Federal Reserve Bank of Philadelphia since 2015. She has also been a director of the Union League Club of Philadelphia since 2016 and a director of the National Association of Corporate Directors-Philadelphia Chapter since 2017. Ms. Johnson brings strategic leadership, operational and financial expertise to our board of directors from her background in leading, managing and growing companies.
Board Composition
Prior to closing our IPO, each of Goh Yong Siang, Domenic J. Dell’Osso, Jr., Bryan J. Lemmerman, Ong Tiong Sin, Boon Sim served as directors pursuant to the board composition provisions of our amended and restated stockholders agreement, that we entered into with certain of our investors, which is further described in “Certain Relationships and Related Party Transactions-Stockholders Agreement” in Item 13 of this annual report. The amended and restated stockholders agreement was terminated prior to the completion of the IPO.
On February 1, 2018, prior to our IPO, the Company entered into an investors’ rights agreement with Maju and Chesapeake, pursuant to which, each of Maju and Chesapeake will have the right to nominate (1) two directors so long as it beneficially owns at least 15% of our then-outstanding shares of capital stock or (2) one director so long as it beneficially owns at least 5% but less than 15% of our then-outstanding shares of capital stock. In addition, the Company entered into an investors’ rights agreement with Senja and Hampton, pursuant to which, Senja and Hampton will have the right to collectively nominate one director so long as it beneficially owns at least 5% of our then-outstanding shares of capital stock.
Our certificate of incorporation and bylaws, as amended and restated, provide that the authorized number of directors may be changed only by resolution of the board of directors. Our amended and restated certificate of incorporation also provide that directors may only be removed for cause. To remove a director not appointed by Maju, Chesapeake or Senja for cause, 662/3% of the voting power of the outstanding voting stock must vote as a single class to remove the director at an annual or special meeting. Our amended and restated certificate of incorporation also provide that, if a director is removed or if a vacancy occurs due to either an increase in the size of the board or the death, resignation, disability, disqualification or other cause, the vacancy will be filled solely by the affirmative vote of a majority of the remaining directors then in office, even if less than a quorum remain, or by a sole remaining director and shall not be filled by the stockholders. However, at any time Maju, Chesapeake, Senja and Hampton have the right to nominate a director under their respective investors’ rights agreement, any vacancy resulting from the death, resignation, disability, disqualification or other cause, of a director nominated by these stockholders will be filled by the applicable nominating stockholder.
The ability of stockholders to remove directors only for cause and the inability of stockholders to call special meetings, may have the effect of delaying or preventing a change in control or management.
Prior to closing our IPO, in accordance with the terms of the certificate of incorporation and bylaws, as amended and restated, the size of our board of directors was increased from five directors to seven directors.
Classified Board of Directors
Pursuant to the terms of our amended and restated certificate of incorporation, our board of directors is divided into three classes, each of which consisting, as nearly as possible, of one-third of the total number of directors constituting our entire board of directors and directors in each class serve staggered three-year terms. At each annual meeting of stockholders, the successors to directors whose terms then expire will be elected to serve from the time of election and qualification until the third annual meeting following such election. The classes of our directors are as follows:
· Class I, consisting of Messrs. Sim and Lemmerman, whose terms will expire at our 2019 annual meeting of stockholders;
· Class II, consisting of Messrs. Ong and Doss, whose terms will expire at our 2020 annual meeting of stockholders; and
· Class III, consisting of Messrs. Goh and Dell’Osso and Ms. Johnson, whose terms will expire at our 2021 annual meeting of stockholders.
The division of our board of directors into three classes with staggered three-year terms may delay or prevent a change of our management or a change in control.
Stockholder Recommendation for Directors
Subject to the provisions of the investors’ rights agreements, stockholders may recommend director candidates for consideration by our nominating and corporate governance committee. Any such recommendation should be submitted in writing to James T. Sutton, Secretary, c/o FTS International, Inc. 777 Main Street, Suite 2900, Fort Worth, Texas 76102. The nominating and corporate governance committee expects to use a similar process to evaluate candidates recommended by stockholders as the one it uses to evaluate candidates otherwise identified by the committee. See “Certain Relationships and Related Transactions, and Director Independence-Investors’ Rights Agreement” in Item 13 of this annual report.
Committees of the Board of Directors
Our board of directors has established an audit committee, a compensation committee and nominating and corporate governance committee, and may establish such other committees as it shall determine from time to time. The charters for each of our committees is available on our website at www.ftsi.com. Each of the standing committees of the board of directors has the responsibilities described below.
Audit Committee
Our audit committee consists of Carol J. Johnson, Ong Tiong Sin and Bryan J. Lemmerman, with Ms. Johnson serving as chair of the audit committee. Our board of directors has determined that Ms. Johnson is independent under the NYSE listing standards and Rule 10A-3 under the Exchange Act and at least a majority of committee members will be independent under such provision by May 3, 2018 (or 90 days of the effectiveness of the registration statement), and all the committee members will be independent under such provisions by February 1, 2019 (or one year after the effective date of the registration statement). Each of the committee members is financially literate within the requirements of the NYSE listing standards and our board of directors has determined that each of Mr. Lemmerman and Ms. Johnson qualifies as an “audit committee financial expert” as that term is defined by the applicable SEC regulations and NYSE corporate governance listing standards. We intend to comply with the independence requirements for all members of the audit committee within the time periods required under the NYSE listing rules and Exchange Act.
The duties of the audit committee are set forth in its charter, which is available in the Corporate Governance section of our website at www.ftsi.com. Our audit committee oversees our accounting and financial reporting process and the audit of our financial statements and assists our board of directors in monitoring our financial systems and legal and regulatory compliance. Our audit committee is responsible for, among other things:
· appointing, approving the compensation of and assessing the independence of our independent registered public accounting firm;
· pre-approving audit and permissible non-audit services, and the terms of such services, to be provided by our independent registered public accounting firm;
· reviewing annually a report by our independent registered public accounting firm regarding the independent registered public accounting firm’s internal quality control procedures and various issues relating thereto;
· coordinating the oversight and reviewing the adequacy of our internal control over financial reporting with both management and our independent registered public accounting firm;
· reviewing and discussing with management and our independent registered public accounting firm our annual and quarterly financial statements and related disclosures;
· periodically reviewing legal compliance matters, periodically reviewing significant accounting and other financial risks or exposures to our company and reviewing and, if appropriate, approving all transactions between our company or its subsidiaries and any related party (as described in Item 404 of Regulation S-K);
· periodically reviewing our code of business conduct and ethics;
· establishing policies for the hiring of employees and former employees of our independent registered public accounting firm; and
· reviewing the audit committee report required by SEC regulations to be included in our annual proxy statement.
The audit committee also has the power to investigate any matter brought to its attention within the scope of its duties and the authority to retain counsel and advisors at our expense to fulfill its responsibilities and duties.
Compensation Committee
Our compensation committee consists of Goh Yong Siang, Ong Tiong Sin, and Domenic J. Dell’Osso, Jr., with Mr. Goh serving as chair of the committee. Our board of directors has determined that each of Messrs. Goh, Ong, and Dell’Osso are independent under the NYSE listing standards and Rule 10C-1 of the Exchange Act and that each of Messrs. Goh and Ong qualifies as a “non-employee director” within the meaning of Rule 16b-3(d)(3) under the Exchange Act and as “outside directors” within the meaning of Section 162(m) of the Internal Revenue Code of 1986, as amended (the “Code”). Our compensation committee is responsible for developing and maintaining our compensation strategies and policies. Our compensation committee is responsible for, among other things:
· reviewing and approving our overall executive and director compensation philosophy to support our overall business strategy and objectives;
· reviewing and approving, or as appropriate, recommending to our board of directors for approval, base salary, cash incentive compensation, equity compensation, and severance rights for our executive officers, including our CEO;
· administering our broad-based equity incentive plans, including the granting of stock awards;
· preparing any report on executive compensation required by the applicable rules and regulations of the SEC and other regulatory bodies;
· managing such other matters that are specifically delegated to our compensation committee by applicable law or by the board of directors from time to time; and
· retaining and terminating compensation consultants to assist in the evaluation of our compensation and approving the fees and other retention terms of such compensation consultants.
The compensation committee also has the power to investigate any matter brought to its attention within the scope of its duties and authority to retain counsel and advisors at our expense to fulfill its responsibilities and duties.
Nominating and Corporate Governance Committee
Our nominating and corporate governance committee consists of Domenic J. Dell’Osso, Jr., Ong Tiong Sin, and Boon Sim, with Mr. Dell’Osso serving as chair of the committee. Our board of directors has determined that each of Messrs. Dell’Osso, Ong, and Sim is independent as defined by NYSE rules.
Our nominating and corporate governance committee oversees and assists our board of directors in reviewing and recommending corporate governance policies and nominees for election to our board of directors and its committees. The nominating and corporate governance committee will be responsible for, among other things:
· assessing, developing, and communicating with our board of directors concerning the appropriate criteria for nominating and appointing directors, including the size and composition of the board of directors, corporate governance policies, applicable listing standards, laws, rules and regulations, and other factors considered appropriate by our board of directors;
· identifying and recommending to our board of directors the director nominees for meetings of our stockholders, or to fill a vacancy on the board of directors, except as set forth in the investors’ rights agreements;
· having sole authority to retain any search firm used to identify director candidates and approve the search firm’s fees and other retention terms;
· assessing and recommending to the board of directors the composition of each of its committees;
· reviewing, as necessary, any executive officer’s request to accept a directorship position with another company;
· developing, assessing and making recommendations to our board of directors concerning corporate governance matters, including appropriate revisions to our amended and restated certificate of incorporation, amended and restated bylaws, corporate governance guidelines and committee charters;
· overseeing the management continuity and succession planning process with respect to our officers;
· overseeing an annual evaluation of our board of directors, its committees, and each director;
· developing with management and monitoring the process of orienting new directors and continuing education for all directors; and
· regularly reporting its activities and any recommendations to our board of directors.
The nominating and corporate governance committee also has the power to investigate any matter brought to its attention within the scope of its duties. It also has the authority to retain counsel and advisors at our expense for any matters related to the fulfillment of its responsibilities and duties.
Section 16(a) Beneficial Ownership Reporting Compliance
Section 16(a) of the Exchange Act requires our directors and executive officers, and persons who own more than ten percent of a registered class of our equity securities, to file with the SEC initial reports of ownership and reports of changes in ownership of common stock and other equity securities of our company. Executive officers, directors and greater than ten percent stockholders are required by SEC regulation to furnish us with copies of all Section 16(a) forms they file.
Our executive officers, directors and ten percent stockholders did not become subject to the reporting requirements of Section 16(a) until February 2, 2018 and, therefore, there were no reports required during the fiscal year ended December 31, 2017.
Code of Business Conduct and Ethics
The board of directors has adopted an amended and restated code of business conduct and ethics that is applicable to all of our employees, officers, and directors, including our principal executive officer, principal financial officer, principal accounting officer, or persons performing similar functions. The code of business conduct and ethics is available on our website at www.ftsi.com. Any waiver of this code for any executive officer or director may be made only by our board of directors or a committee of the board of directors and will be promptly disclosed as required by applicable U.S. federal securities laws and the corporate governance rules of the NYSE. We expect that any amendment or waiver to the code will be disclosed on our website.
Item 11.
Item 11. Executive Compensation
Our compensation committee consists of Goh Yong Siang, Ong Tiong Sin, and Domenic J. Dell’Osso, Jr., with Mr. Goh serving as chair of the committee. Our board of directors has determined that each of Messrs. Goh, Ong, and Dell’Osso are independent under the NYSE listing standards and Rule 10C-1 of the Exchange Act and that each of Messrs. Goh and Ong qualifies as a “non-employee director” within the meaning of Rule 16b-3(d)(3) under the Exchange Act and as “outside directors” within the meaning of Section 162(m) of the Code. Our compensation committee will be responsible for, among other things:
· reviewing and approving our overall executive and director compensation philosophy to support our overall business strategy and objectives;
· reviewing and approving, or as appropriate, recommending to our board of directors for approval, base salary, cash incentive compensation, equity compensation, and severance rights for our executive officers, including our CEO;
· administering our broad-based equity incentive plans, including the granting of stock awards;
· preparing any report on executive compensation required by the applicable rules and regulations of the SEC and other regulatory bodies;
· managing such other matters that are specifically delegated to our compensation committee by applicable law or by the board of directors from time to time; and
· retaining and terminating compensation consultants to assist in the evaluation of our compensation and approving the fees and other retention terms of such compensation consultants.
Additional information regarding the processes and procedures of the Compensation Committee in recommending and determining compensation for our directors and executive officers is set forth below under the heading “Compensation Discussion and Analysis.”
COMPENSATION DISCUSSION AND ANALYSIS
In this section, we describe and discuss the principles and policies used in setting the compensation of our named executive officers and other executive officers. Our named executive officers for the fiscal year ended December 31, 2017 were:
· Michael J. Doss, Chief Executive Officer;
· Lance Turner, Chief Financial Officer and Treasurer;
· Buddy Petersen, Chief Operating Officer;
· Perry A. Harris, Senior Vice President, Commercial; and
· Karen Thornton, Chief Administrative Officer.
Objective and Design of Compensation Policy
The objective of the Company’s executive compensation policy is to:
· attract and retain exceptional individuals as executive officers;
· provide key executives with motivation to perform to the full extent of their abilities to maximize the performance of the Company and deliver enhanced value to the Company’s shareholders; and
· compensate key executives for outstanding performance.
What the Company’s Executive Compensation Program is Designed to Reward
Overall, the Company’s executive compensation program is designed to reward the contributions of each individual executive officer, to ensure that each executive officer’s interest is aligned with those of the Company’s shareholders, and to provide sufficient incentives to executive officers to ensure their dedication to the Company. As discussed further below, the Company seeks to achieve these goals by providing sufficient base salaries to compensate executive officers for the day-to-day performance of their duties and awarding cash bonuses when the executive attains the personal or corporate goals and objectives established by the Company. Also, from time to time, the Company grants equity-based awards when it believes that such equity awards will further align the interests of executive officers with those of the Company’s shareholders and provide an additional incentive to executive officers to contribute to the achievement of the Company’s financial and strategic objectives.
General Executive Compensation Policies
Process for Setting Total Compensation
Since the Company was privately held until February 2, 2018, the compensation committee did not retain an outside consultant or advisor to advise it regarding the Company’s executive compensation program for fiscal year 2017. The compensation committee has historically reviewed the compensation policies and levels of companies that are engaged in the same industry as the Company, and has conducted the review without the advice of an outside consultant or advisor. While the compensation committee conducted this review and considered the information prior to setting compensation levels for fiscal year 2017, it did not rely on any peer group analysis or engage in any benchmarking.
Upon hiring or promoting a named executive officer, the compensation committee will set the initial levels of base salary and other compensation on the basis of subjective factors, including experience, individual achievements, and level of responsibility assumed at the Company, and may consider market compensation practices from time to time, as discussed in the preceding paragraph. Actual base salaries, cash bonuses, and equity-based awards for each named executive officer may be adjusted from year to
year based upon each named executive officer’s periodic review and level of attainment of personal and corporate goals and objectives, including Company financial and safety performance, shareholder return, and such other factors as the compensation committee deems appropriate and in the best interests of the Company’s shareholders.
Each named executive officer’s periodic review is a subjective process whereby the Chief Executive Officer or the compensation committee (as applicable, as described below) evaluates various factors relevant to the named executive officer’s contributions to the Company, such as the executive’s role in the development and execution of strategic plans, leadership skills, motivation, and involvement in industry groups. The weight given to such factors may vary from one named executive officer to another.
The compensation committee seeks recommendations from the Chief Executive Officer regarding changes to or increases in the overall compensation level or any particular element of compensation for the other named executive officers. In addition, the Chief Executive Officer is principally responsible for reviewing each other named executive officer’s performance, and for making recommendations for the Company’s compensation plan for such executive officer for the following fiscal year. The compensation committee reviews the recommendations of the Chief Executive Officer in light of his proximity to the other executives and his knowledge of their contributions to the Company. The compensation committee independently reviews the performance of the Company’s Chief Executive Officer and determined any changes to or increases in the overall compensation level or any particular element of compensation for the Chief Executive Officer.
Consideration of Shareholder Advisory Vote on Executive Compensation
Being a newly public Company, the Company was not required to provide its shareholders with the opportunity to cast an advisory vote on executive compensation (a “say-on-pay vote”) at the annual meeting of shareholders held in 2017. The compensation committee will consider the outcome of any say-on-pay vote occurring at any annual meeting of the shareholders of the Company when making future compensation decisions for the named executive officers. The Company is scheduled to hold a say-on-pay vote at the Company’s annual meeting of shareholders to be held in 2019.
Elements of Compensation
The Company’s executive compensation program consists of the following elements of compensation, each described in greater depth below:
· Base Salary;
· Annual Bonus;
· Discretionary Bonus;
· Equity-Based Compensation;
· Perquisites; and
· General Benefits.
In determining the different elements of compensation to provide to the named executive officers, the compensation committee does not adhere to a specific allocation between short-term and long-term compensation, or between cash and non-cash compensation. Instead, the compensation committee determines the elements of compensation in a manner designed to reward strong financial performance, provide overall compensation opportunities that are sufficient to attract and retain highly skilled named executive officers, and ensure that named executive officers’ interests are aligned with those of the Company’s shareholders. This may result in the named executive officers receiving all cash compensation in some years (through base salary and annual bonuses) and a combination of cash and equity-based compensation in other years (through base salary, annual bonuses and equity awards).
(1) Base Salary
The Company pays base salaries to named executive officers because the Company believes that base salaries are essential to recruiting and retaining qualified executives. In addition, base salaries create an incentive for named executive officers to make meaningful contributions to the Company’s success because they are subject to increase based on the executive’s performance. The compensation committee sets the initial base salary level upon the hiring or promotion of a named executive officer and may incorporate base salary into related employment contracts. Base salary levels are determined initially based on the named executive officer’s previous experience and employment, and the named executive officer’s expected duties and responsibilities with respect to the Company. Thereafter, the compensation committee may change a named executive officer’s base salary from time to time, based
on the results of the named executive officer’s periodic review (which is conducted by the Chief Executive Officer or his designee for each of the other named executive officers and by the compensation committee for the Chief Executive Officer), and based on the compensation committee’s subjective assessment of the Company’s overall performance during the evaluation period.
(2) Annual Bonus Compensation
Historically, the board of directors has annually approved short-term incentive plans. In December 2016, our board of directors approved the 2017 short-term incentive plan (the “2017 STIP”), to motivate employees to drive outstanding company performance, provide flexibility given the uncertain business environment and improve employee retention. The executive officers were eligible to participate.
The 2017 incentives were based on the achievement of:
· Financial targets for Adjusted EBITDA;
· Safety performance as measured by our total recordable incident rate (“TRIR”); and
· Department key performance indicators (“KPIs”).
The 2017 STIP provided for a target award equal to 100% of base salary for Mr. Doss, 80% of base salary for Mr. Turner, 80% of base salary for Mr. Petersen, 60% of base salary for Mr. Harris and 60% of base salary for Ms. Thornton. The payout under the 2017 STIP was based 55% on the financial target, 20% on the safety target and 25% on department KPIs. The compensation committee set targets for each quarter of 2017, based on the recommendations of the Chief Executive Officer. The incentives were contingent upon the minimum threshold being achieved. Under the 2017 STIP, the formula for determining the potential payout percentage for a named executive officer’s financial target, was: (Actual Adjusted EBITDA-Minimum Threshold) / (Financial Goal-Minimum Threshold). If the financial goal was achieved, the payout percentage would be 100%. If the financial goal was exceeded, the payout percentage could reach a maximum of 200%.
The following targets were set each quarter:
KPIs were determined by the manager of each named executive officer, except for Mr. Doss. The KPIs for Mr. Doss were determined by the board of directors. The 2017 STIP awards are paid out subsequent to the quarter for which the performance measures relate.
Under the terms of the 2017 STIP, the Chief Executive Officer was delegated the authority to award amounts above the maximum payout based on the individual performance of and contribution by the named executive officer. Such additional payouts are in the discretion of the Chief Executive Officer. Each named executive officer, other than the Chief Executive Officer, received a discretionary payment in excess of the maximum award.
The 2017 Compensation Table Summary below includes the payouts to the named executive officers under the 2017 STIP.
(3) Discretionary Bonus
The compensation committee retains discretion to grant bonus compensation to the named executive officers and other employees of the Company outside of the Bonus Plan. From time to time the Company may award discretionary annual bonuses to the named executive officers and may agree, in hiring or promoting a named executive officer, to a target bonus opportunity, expressed as a percentage of base salary or otherwise, in any case, to be paid only if the Company determines that the Company has attained its financial performance goals or other objectives. The Company has entered into retention bonus agreements with two of the named executive officers, Mr. Turner and Ms. Thornton. Pursuant to the terms of their respective retention bonus agreements, during 2017,
Mr. Turner received a bonus equal to $40,000 and Ms. Thornton received a bonus equal to 25% of her base salary as of August 8, 2015, as a result of their service to the Company and the Company’s achievement of pre-established adjusted EBITDA targets for the Company.
In addition, in 2017 Mr. Harris received a bonus payment equal to 40% of Mr. Harris’ base salary, pursuant to the terms of his employment agreement, based on Mr. Harris’ achievement of performance criteria set by Mr. Harris’ supervising officer. The bonus was paid in four equal, quarterly installments.
The 2017 Compensation Table Summary below includes the discretionary payouts to the named executive officers.
(4) Equity Compensation
2014 LTIP
The Company awards equity-based compensation to named executive officers in order to provide a link between the long-term results achieved for its shareholders and the rewards provided to named executive officers, thereby ensuring that such officers have a continuing stake in the Company’s long-term success.
In March 2014, our board of directors adopted, and our stockholders approved, the 2014 Long-Term Incentive Plan (the “2014 LTIP”). The purposes of the 2014 LTIP was to provide an additional incentive to selected employees whose contributions were essential to the growth and success of our business in order to strengthen the commitment of employees to us, motivate employees to faithfully and diligently perform their responsibilities, and attract and retain competent and dedicated persons whose efforts would result in our long-term growth and profitability. The 2014 LTIP provided for grants of restricted stock units, and restricted stock under a Chief Executive Officer discretionary pool, to employee participants. No equity awards were granted to any named executive officers during fiscal year 2017 under the 2014 LTIP. All outstanding awards under the 2014 LTIP vested immediately before the effectiveness of the registration statement on February 1, 2018, and were settled in cash. Following the effectiveness of the registration statement, the 2014 LTIP was terminated and no further awards will be made under the 2014 LTIP.
Shares Available. The maximum number of shares of our common stock that could be issued under the 2014 LTIP, before adjusting for our 69.258777:1 reverse stock split in connection with the IPO, was 55,025,000. Under the 2014 LTIP, 55,000,000 shares were available for issuance as restricted stock units and 25,000 were available for issuance as restricted stock or restricted stock units at the discretion of the CEO. The shares under the 2014 LTIP were subject to adjustment in the event of, among other things, a merger, recapitalization, reorganization, spin-off, spin-out, special dividend, stock split, combination or exchange of shares or other change in corporate structure affecting our common stock.
Eligibility. Any employee of the Company or its affiliates selected by the administrator in his or its sole discretion was eligible to participate in the 2014 LTIP.
Administration. The Compensation Committee administered the 2014 LTIP, except that the CEO administered the 2014 LTIP with respect to awards granted under the CEO discretionary pool. The administrator had broad discretion to administer the 2014 LTIP, including the power to determine to whom and when awards were granted, to determine the amount of awards, to determine the terms and conditions, not inconsistent with the terms of the 2014 LTIP of each award granted, to determine the effect, if any, of employment, severance and other agreements on the awards, to determine fair market value of the awards, to adopt, alter and repeal administrative practices governing the 2014 LTIP, to construe and interpret the terms and provisions of the 2014 LTIP and to execute all other responsibilities permitted or required under the 2014 LTIP. The 2014 LTIP was administered in accordance with, to the extent applicable, Rule 16b-3 under the Exchange Act.
Restricted Stock Awards. A restricted stock award is a grant of shares of common stock subject to a risk of forfeiture, restrictions on transferability and any other restrictions determined by the administrator. Except as otherwise provided under the terms of the 2014 LTIP or an award agreement, the holder of a restricted stock award under the 2014 LTIP generally had rights as a stockholder. All outstanding restricted stock units vested immediately before the effectiveness of the registration statement on February 1, 2018, and were settled in cash.
2018 LTIP
On February 1, 2018, our board of directors and stockholders adopted the 2018 Plan. The material terms of the 2018 Plan are as follows:
Purpose. The purpose of the 2018 Plan is to attract and retain officers, employees, directors, consultants and other key personnel and to provide those persons incentives and awards for performance.
Administration; Effectiveness. The 2018 Plan will generally be administered by the compensation committee of our board of directors. The compensation committee has the authority to determine eligible participants in the 2018 Plan, and to interpret and make determinations under the 2018 Plan. Any interpretation or determination by the compensation committee under the 2018 Plan will be final and conclusive. The compensation committee may delegate all or any part of its authority under the 2018 Plan to any subcommittee thereof, and may delegate its administrative duties or powers to one or more of our officers, agents or advisors.
Shares Available for Awards under the 2018 Plan. Subject to adjustment as described in the 2018 Plan, the number of shares of our common stock available for awards under the 2018 Plan is 2,823,095, plus any shares of our common stock that become available under the 2018 Plan as a result of forfeiture, cancellation, expiration, or cash settlement of awards (the “Available Shares”), with such shares subject to adjustment to reflect any split or combination of our common stock. The Available Shares may be shares of original issuance, treasury shares or a combination of the foregoing.
The 2018 Plan also contains the following customary limits: (1) calendar year limits relating to the grant of stock options and stock appreciation rights and for restricted stock, restricted stock units, performance shares and/or other stock-based awards that are performance-based awards intended to satisfy the requirements for “qualified performance-based compensation” under Section 162(m) of the Code, or Qualified Performance-Based Awards; and (2) limits on the aggregate maximum value that a participant may receive in respect of an award of performance units and/or other awards payable in cash that are Qualified Performance-Based Awards, or a cash incentive award that is a Qualified Performance-Based Award in any calendar year.
Share Counting. The aggregate number of shares of our common stock available for award under the 2018 Plan will be reduced by one share of our common stock for every one share of our common stock subject to an award granted under the 2018 Plan.
The following shares of our common stock will be added (or added back, as applicable) to the aggregate number of shares of our common stock available under the 2018 Plan: (1) shares subject to an award that is cancelled or forfeited, expires or is settled for cash (in whole or in part); (2) shares of our common stock withheld by us in payment of the exercise price of a stock option granted under the 2018 Plan; (3) shares of our common stock tendered or otherwise used in payment of the exercise price of a stock option granted under the 2018 Plan; (4) shares of our common stock withheld by us or tendered or otherwise used to satisfy a tax withholding obligation; provided, however, that with respect to restricted stock, this provision will only be in effect until the ten-year anniversary of the date the 2018 Plan is approved by our stockholders; and (5) shares of our common stock subject to an appreciation right granted under the 2018 Plan that are not actually issued in connection with the settlement of such appreciation right. In addition, if under the 2018 Plan a participant has elected to give up the right to receive compensation in exchange for shares of our common stock based on fair market value, such shares of our common stock will not count against the aggregate number of shares of our common stock available under the 2018 Plan.
Shares of our common stock issued or transferred pursuant to awards granted under the 2018 Plan in substitution for or in conversion of, or in connection with the assumption of, awards held by awardees of an entity engaging in a corporate acquisition or merger with us or any of our subsidiaries, or substitute awards, will not count against, nor otherwise be taken into account in respect of, the share limits under the 2018 Plan. Additionally, shares of common stock available under certain plans that we or our subsidiaries may assume in connection with corporate transactions from another entity may be available for certain awards under the 2018 Plan, but will not count against, nor otherwise be taken into account in respect of, the share limits under the 2018 Plan.
Types of Awards Under the 2018 Plan. Pursuant to the 2018 Plan, we may grant restricted stock units, restricted stock, stock options (including incentive stock options as defined in Section 422 of the Code, or Incentive Stock Options), appreciation rights, cash incentive awards, performance shares, performance units, and certain other awards based on or related to shares of our common stock.
Each grant of an award under the 2018 Plan will be evidenced by an award agreement or agreements, which will contain such terms and provisions as the compensation committee may determine, consistent with the 2018 Plan. Those terms and provisions include the number of our shares of our common stock subject to each award, vesting terms and provisions that apply upon events such as retirement, death or disability of the participant or in the event of a change in control. A brief description of the types of awards which may be granted under the 2018 Plan is set forth below.
Restricted Stock Units. Restricted stock units awarded under the 2018 Plan constitute an agreement by us to deliver shares of our common stock, cash, or a combination thereof, to the participant in the future in consideration of the performance of services, but subject to the fulfillment of such conditions (which may include the achievement of management objectives) during the
restriction period as the compensation committee may specify. Each grant or sale of restricted stock units may be made without additional consideration or in consideration of a payment by the participant that is less than the fair market value of shares of our common stock on the date of grant. During the restriction period applicable to restricted stock units, the participant will have no right to transfer any rights under the award and will have no rights of ownership in the shares of our common stock underlying the restricted stock units and no right to vote them. Rights to dividend equivalents may be extended to and made part of any restricted stock unit award at the discretion of and on the terms determined by the compensation committee. Each grant of restricted stock units will specify that the amount payable with respect to such restricted stock units will be paid in cash, shares of our common stock, or a combination of the two.
Restricted Stock. Restricted stock constitutes an immediate transfer of the ownership of shares of our common stock to the participant in consideration of the performance of services, entitling such participant to dividend, voting and other ownership rights, subject to the substantial risk of forfeiture and restrictions on transfer determined by the compensation committee for a period of time determined by the compensation committee or until certain management objectives specified by the compensation committee are achieved. Each such grant or sale of restricted stock may be made without additional consideration or in consideration of a payment by the participant that is less than the fair market value per share of our common stock on the date of grant.
Any grant of restricted stock may specify the treatment of dividends or distributions paid on restricted stock that remains subject to a substantial risk of forfeiture.
Stock Options. Stock options granted under the 2018 Plan may be either Incentive Stock Option or non-qualified stock options Incentive Stock Options. Except with respect to substitute awards, Incentive Stock Options and non-qualified stock options must have an exercise price per share that is not less than the fair market value of a share of our common stock on the date of grant. The term of a stock option may not extend more than ten years after the date of grant.
Each grant will specify the form of consideration to be paid in satisfaction of the exercise price.
Appreciation Rights. The 2018 Plan provides for the grant of appreciation rights. An appreciation right is a right to receive from us an amount equal to 100%, or such lesser percentage as the compensation committee may determine, of the spread between the base price and the value of shares of our common stock on the date of exercise.
An appreciation right may be paid in cash, shares of our common stock or any combination thereof. Except with respect to substitute awards, the base price of an appreciation right may not be less than the fair market value of a common share on the date of grant. The term of an appreciation right may not extend more than ten years from the date of grant.
Cash Incentive Awards, Performance Shares, and Performance Units. Performance shares, performance units and cash incentive awards may also be granted to participants under the 2018 Plan. A performance share is a bookkeeping entry that records the equivalent of one share of our common stock, and a performance unit is a bookkeeping entry that records a unit equivalent to $1.00 or such other value as determined by the compensation committee. Each grant will specify the number or amount of performance shares or performance units, or the amount payable with respect to cash incentive awards, being awarded, which number or amount may be subject to adjustment to reflect changes in compensation or other factors.
These awards, when granted under the 2018 Plan, become payable to participants upon of the achievement of specified management objectives and upon such terms and conditions as the compensation committee determines at the time of grant. Each grant may specify with respect to the management objectives a minimum acceptable level of achievement and may set forth a formula for determining the number of performance shares or performance units, or the amount payable with respect to cash incentive awards, that will be earned if performance is at or above the minimum or threshold level, or is at or above the target level but falls short of maximum achievement. Each grant will specify the time and manner of payment of cash incentive awards, performance shares of performance units that have been earned, and any grant may further specify that any such amount may be paid or settled in cash, shares of our common stock, restricted stock, restricted stock units or any combination thereof. Any grant of performance shares may provide for the payment of dividend equivalents in cash or in additional shares of our common stock.
Other Awards. The compensation committee may grant such other awards that may be denominated or payable in, valued in whole or in part by reference to, or otherwise based on, or related to, shares of our common stock or factors that may influence the value of such shares of our common stock, including, without limitation, convertible or exchangeable debt securities, other rights convertible or exchangeable into shares of our common stock, purchase rights for shares of our common stock, awards with value and payment contingent upon our performance of specified subsidiaries, affiliates or other business units or any other factors designated by the compensation committee, and awards valued by reference to the book value of the shares of our common stock or the value of securities of, or the performance of our subsidiaries, affiliates or other business units.
Adjustments; Corporate Transactions. The compensation committee will make or provide for such adjustments in the: (1) number of shares of our common stock covered by outstanding stock options, appreciation rights, restricted stock, restricted stock units, performance shares and performance units granted under the 2018 Plan; (2) if applicable, number of shares of our common stock covered by other awards granted pursuant to the 2018 Plan; (3) exercise price or base price provided in outstanding stock options and appreciation rights; (4) kind of shares covered thereby; (5) cash incentive awards; and (6) other award terms, as the compensation committee determines to be equitably required in order to prevent dilution or enlargement of the rights of participants that otherwise would result from (a) any stock dividend, stock split, combination of shares, recapitalization or other change in our capital structure, (b) any merger, consolidation, spin-off, spin-out, split-off, split-up, reorganization, partial or complete liquidation or other distribution of assets, issuance of rights or warrants to purchase securities or (c) any other corporate transaction or event having an effect similar to any of the foregoing.
In the event of any such transaction or event, or in the event of a change in control (as defined in the 2018 Plan), the compensation committee may provide in substitution for any or all outstanding awards under the 2018 Plan such alternative consideration (including cash), if any, as it may in good faith determine to be equitable under the circumstances and will require in connection therewith the surrender of all awards so replaced in a manner that complies with Section 409A of the Code. In addition, for each stock option or appreciation right with an exercise price greater than the consideration offered in connection with any such transaction or event or change in control, the compensation committee may in its discretion elect to cancel such stock option or appreciation right without any payment to the person holding such stock option or appreciation right. The compensation committee will make or provide for such adjustments to the numbers and kind of shares available for issuance under the 2018 Plan and the share limits of the 2018 Plan as the compensation committee in its sole discretion may in good faith determine to be appropriate in connection with such transaction or event. However, any adjustment to the limit on the number of shares of our common stock that may be issued upon exercise of Incentive Stock Options will be made only if, and to the extent, such adjustment would not cause any option intended to qualify as an Incentive Stock Option to fail to so qualify.
Transferability of Award. Except as otherwise provided by the compensation committee, no stock option, appreciation right, restricted share, restricted stock unit, performance share, performance unit, cash incentive award, other award or dividend equivalents paid with respect to awards made under the 2018 Plan may be transferred by a participant.
Amendment and Termination of the 2018 Plan. Our board of directors generally may amend the 2018 Plan from time to time, in whole or in part. However, if any amendment (1) would materially increase the benefits accruing to participants under the 2018 Plan, (2) would materially increase the number of shares of our common stock which may be issued under the 2018 Plan, (3) would materially modify the requirements for participation in the 2018 Plan, or (4) must otherwise be approved by our stockholders in order to comply with applicable law or the rules of the NYSE, then such amendment will be subject to stockholder approval and will not be effective unless and until such approval has been obtained.
Our board of directors may, in its discretion, terminate the 2018 Plan at any time. Termination of the 2018 Plan will not affect the rights of participants or their successors under any awards outstanding and not exercised in full on the date of termination. No grant will be made under the 2018 Plan more than ten years after the effective date of the 2018 Plan, but all grants made on or prior to such date shall continue in effect thereafter subject to the terms of the 2018 Plan.
The restricted stock units will be settled in shares of our common stock subject to the discretion of the compensation committee to settle the restricted stock units in cash. Most of the shares authorized under the 2018 Plan were issued in connection with the IPO.
(5) Perquisites
Other than as disclosed below, during our fiscal year ended December 31, 2017, our executives did not receive any perquisites and were not entitled to benefits that are not otherwise available to all of our employees.
(6) General Benefits
The following are standard benefits offered to all eligible Company employees, including the executive officers.
Retirement Benefits. The Company offers a 401(k) defined contribution retirement plan for all eligible employees, including the named executive officers, known as the FTS International, Inc. 401(k) Plan (the “401(k) Plan”). The 401(k) is a voluntary contributory plan, which allows a participant to defer, by payroll deductions, from 0% to 100% of the participant’s annual compensation, limited to certain annual maximums set by the Code. The 401(k) Plan has historically provided a discretionary matching contribution to each participant’s account. The Company suspended matching contributions in July 2015 and resumed making contributions in July 2017. Each named executive officer received a matching contribution from the Company during 2017;
however, such amounts, together with all other perquisites, were less than $10,000 in the aggregate per named executive officer. Consequently, such amounts are not reflected in the 2017 Summary Compensation Table.
Health and Welfare Benefits. The Company makes available medical, dental, vision, prescription drug, flexible spending accounts, health savings accounts, life insurance, and disability coverage to all active eligible employees, including the named executive officers.
Paid Time-Off Benefits. The Company provides paid time off, bereavement leave, maternity leave, and other paid holidays to all employees, including the named executive officers.
2017 Summary Compensation Table
The following table summarizes the compensation of our principal executive officer, principal financial officer, and three most highly compensated executive officers other than the principal executive officer and principal financial officer, during the years ended December 31, 2015, 2016 and 2017.
(1) With respect to Mr. Harris, for 2015, column (d) includes a retention bonus payment equal to 10% of Mr. Harris’ base salary pursuant to the terms of his employment agreement.
(2) For the fiscal year 2016, our board of directors approved a cash bonus pool amount to be paid as discretionary bonuses. Our board of directors delegated authority to allocate the bonus pool to our chief executive officer in his sole discretion. These discretionary bonuses were paid in recognition of each of the named executive officers’ contributions to the Company’s cost reduction initiatives.
(3) With respect to Messrs. Doss, Turner and Petersen, for 2016, the amount set forth in column (d) represents the discretionary bonuses paid pursuant to the cash bonus pool. With respect to Mr. Harris, for 2016, column (d) includes a retention bonus payment equal to 20% of Mr. Harris’ base salary pursuant to the terms of his employment agreement. With respect to Ms. Thornton, for 2016, column (d) includes a discretionary bonus equal to $15,000 pursuant to the discretionary bonus pool, a performance bonus equal to $20,000 and a retention bonus equal to $11,714 pursuant to the terms of her retention bonus agreement dated December 19, 2016.
(4) With respect to Mr. Turner, for 2017, the amount set forth in column (d) represents a retention bonus paid pursuant to the terms of a retention bonus agreement, dated August 5, 2015, which entitled Mr. Turner to a retention bonus equal to $40,000 payable upon the Company’s achievement of the pre-determined Adjusted EBITDA thresholds. With respect to Mr. Harris, for 2017, column (d) includes a retention bonus payment equal to 40% of Mr. Harris’ base salary in 2017 pursuant to the terms of his employment agreement. With respect to Ms. Thornton, for 2017, column (d) includes a retention bonus payment equal to 25% of Ms. Thornton’s base salary in 2015 pursuant to the terms of her retention bonus agreement dated March 29, 2017.
(5) With respect to all named executive officers, for 2017, the amount set forth in column (g) represents payments made under the Company’s 2017 Short Term Incentive Plan. For additional information, see “-Short Term Incentive Plans-2017 Short Term Incentive Plan” in this Item 11. The payments under the 2017 STIP were made to all named executive officers on or before January 12, 2018.
(6) See the All Other Compensation Table for additional information.
All Other Compensation Table
(1) This column represents the matching contributions made by the Company for the benefit of named executive officers under the 401(k) Plan. The 401(k) Plan is discussed in more detail in the “Elements of Compensation” in this Item 11.
(2) This column represents the value of other benefits provided to the named executive officers in 2015 and includes premiums for life insurance policies for each named executive officer in which the Company is not the beneficiary. In addition, the amount for Mr. Harris reflects the value associated with Mr. Harris’ personal use of a corporate vehicle.
(3) With respect to Mr. Petersen, for 2015, the perquisites and other personal benefits were in the aggregate less than $10,000.
(4) For 2016 and 2017 the perquisites and other personal benefits were in the aggregate less than $10,000 for each named executive officer.
Grants of Plan-Based Awards
The following table reflects each grant of an award made to a named executive officer during fiscal year 2017 under any plan.
(1) Amounts shown in these columns represent each named executive officer’s non-discretionary incentive bonus opportunity under the 2017 STIP in which such named executive officers participated. The “Target” amount represents the named executive officer’s target bonus if the performance goals under the 2017 STIP was achieved at the target level. The “Threshold” amount represents named executive officer’s minimum bonus if the performance goal under the bonus program was achieved at the minimum level. The “Maximum” amount represents the named executive officer’s target bonus if the performance goals under the 2017 STIP was achieved at the Maximum level.
(2) The 2017 STIP provided for quarterly targets, based on the recommendations of the Chief Executive Officer. The amounts reflected in each column reflects the Threshold, Target and Maximum, aggregated for each of the four quarters occurring in 2017.
(3) Under the terms of the 2017 STIP, the Chief Executive Officer was delegated the authority to award amounts above the Maximum payout based on the individual performance of and contribution by the named executive officer. Such additional payouts are in the discretion of the Chief Executive Officer. Each named executive officer, other than the Chief Executive Officer, received a discretionary payment in excess of the Maximum award.
Summary of Employment Agreements
It is the Company’s general philosophy that all of the Company’s employees should be “at will” employees, thereby allowing both the Company and the employee to terminate the employment relationship at any time and without restriction or financial obligation, with limited exceptions.
We have not entered into employment agreements with any of our executive officers, other than Perry Harris. We entered into an employment agreement with Mr. Harris in December 2014 in connection with our acquisition of the assets of J-W Wireline Company. Our agreement with Mr. Harris had a term of three years and expired on December 6, 2017. The Company has no continuing obligations to Mr. Harris following the expiration of his employment agreement.
The employment agreement with Mr. Harris provided for a base salary of not less than $320,000 per year. Mr. Harris was also eligible to participate in any short-term incentive plan and in any long-term incentive plan with an annual target award percentage under each plan equal to or exceeding 40% of his base salary. Despite the expiration of the employment agreement, Mr. Harris continues to be subject to non-solicitation, confidentiality and non-compete provisions, which remain effective during Mr. Harris’ employment and continue for a period of one year following the termination of Mr. Harris’ employment.
Mr. Harris was also entitled to retention bonuses equal to 10%, 20% and 40% of his annual base salary set forth in the employment agreement upon his completion of one, two and three years of service, respectively, with the Company and subject to meeting certain performance criteria. Each retention bonus was payable in installments in the calendar year following the applicable service anniversary.
Additionally, if Mr. Harris’ employment had been terminated before the end of the three year term:
· due to death or disability, he would have received earned but unpaid compensation, any unpaid short-term incentive plan compensation for the calendar year ending before his termination, a prorated amount of his target short-term incentive plan compensation for the portion of the year he was employed and any earned but unpaid retention bonus;
· by us without cause or by him for good reason (each as defined in his employment agreement), he would have received earned but unpaid compensation, his base salary through the one-year anniversary of the termination and the average of his short-term incentive plan compensation paid or payable for the prior three years or the average of his short-term
incentive plan compensation for the number of years during which he was eligible to participate in the short-term incentive plan if less than three and any earned but unpaid retention bonus;
· by us for cause or by him without good reason, he would have received earned but unpaid compensation and if the termination is by him without good reason and occurs after the third anniversary of the date of the agreement, he would have received earned but unpaid retention bonus; and
· by us without cause or by him for good reason within two years after a change of control (as defined in his employment agreement) occurred, he would have received earned but unpaid compensation and a lump sum cash payment equal to the sum of (1) his base salary at the highest annual rate in effect on or before his termination and (2) an amount equal to the greater of (a) the average of his short-term incentive compensation paid or payable had he remained employed for the prior three full fiscal years ending before the date of termination, or the average of his short-term incentive plan compensation for the number of years during which he was eligible to participate in the short-term incentive plan if less than three; (b) the short-term incentive plan compensation paid to him for the last full fiscal year of his employment; and (c) his target short-term incentive plan compensation for the fiscal year that includes the date of termination.
All of the severance payments described above were subject to Mr. Harris’ execution of a release of claims and compliance with the non-solicitation, confidentiality and non-compete provisions of the employment agreement.
Outstanding Equity Awards at Fiscal Year-End
The following table reflects outstanding equity awards as of December 31, 2017, for each of the named executive officers, which is limited to outstanding equity awards issued under our 2014 LTIP. The numbers below are before adjusting for our 69.258777:1 reverse stock split that occurred on February 1, 2018.
(1) The market value is based upon the initial public offering price of $18.00 per share.
(2) The restricted stock units vested immediately before effectiveness of the registration statement on February 1, 2018, and settled in cash.
Option Exercises and Stock Vested Table
During the fiscal year ended December 31, 2017, no stock options, stock appreciation rights or similar instruments were exercised by any named executive officer. During the fiscal year ended December 31, 2017, no restricted stock, restricted stock units or similar instruments, held by any named executive officer, vested.
No Pension Benefits
Aside from our 401(k) Plan, we do not maintain any pension plan or arrangement under which our named executive officers are entitled to participate or receive post-retirement benefits.
No Nonqualified Deferred Compensation
The Company does not maintain any defined contribution or other plan that provides for the deferral of compensation on a basis that is not tax-qualified.
Potential Payments Upon Termination or Change in Control
We have entered into severance agreements with Messrs. Doss, Turner, and Petersen that provide for payments to be made to the respective named executive officer in connection with a termination of employment. These agreements have an initial term of one-year that expired on May 3, 2017. The severance agreements were extended on June 15, 2017 for an additional one-year period, and now expire on May 3, 2018. Each of Messrs. Doss and Petersen is eligible to receive a lump sum equal to 1.5 times his then-current annual base salary as severance following his termination of employment by us without cause (as defined in the agreement), or by the executive for good reason (as defined in the agreement), subject to his execution of a release of claims and compliance with the non-solicitation, confidentiality and non-compete provisions in his severance agreement and under any other agreement to which the Company (or any of its affiliates) and such executive are a party. Mr. Turner is eligible to receive a lump sum equal to 1.0 times his then-current annual base salary as severance following his termination of employment by us without cause (as defined in the agreement), or by the executive for good reason (as defined in the agreement), subject to his execution of a release of claims and compliance with the non-solicitation, confidentiality and non-compete provisions in the severance agreements and under any other agreement to which the Company (or any of its affiliates) and Mr. Turner are a party.
On June 15, 2017 we entered into a retention agreement with Ms. Thornton. The agreement provided that Ms. Thornton will receive a retention bonus equal to $108,000 and is payable on June 15, 2018, subject to Ms. Thornton’s continued employment with the Company through the bonus payment date. If Ms. Thornton is terminated by us without cause or the Company completes a sale of a majority of its equity or substantially all of its assets, Ms. Thornton is entitled to the payment of the full retention bonus, subject to her execution of a release of claims.
DIRECTOR COMPENSATION
During the fiscal year ended December 31, 2017, the Company did not pay any compensation to our directors, but generally reimbursed our directors for reasonable out-of-pocket expenses that they incurred in connection with their service as directors, in accordance with our general expense reimbursement policies. Each director is fully indemnified by us, pursuant to individual indemnification agreements entered into on February 1, 2018 and the certificate of incorporation, for actions associated with being a director to the fullest extent permitted under Delaware law.
We believe that attracting and retaining qualified non-employee directors will be critical to our future growth. As such, the Company expects that it will provide compensation that is comparable to the compensation that is offered to directors of companies that are similar to ours, including equity-based compensation, in the future. Currently, the Company reimburses our independent directors for reasonable out-of-pocket expenses that they incur in connection with their service as directors, in accordance with our general expense reimbursement policies.
Change in Control or Other Arrangements
Except for the foregoing, and the arrangements described above with Mr. Doss, there are no other arrangements for compensation of directors and there are no employment contracts between the Company and its directors or any change in control arrangements. See “Potential Payments Upon Termination or Change in Control” in this Item 11 for information regarding arrangements with Mr. Doss.
Outstanding Equity Awards at Fiscal Year End.
The Company did not have any outstanding equity awards at the end of its fiscal year ended December 31, 2017 and did not have any equity compensation plans in effect at the end of its fiscal year ended December 31, 2017 for directors. Mr. Doss’ equity awards described under “Outstanding Equity Awards at Fiscal Year-End” in this Item 11 relates to his service as an employee of the Company.
Compensation Committee Interlocks and Insider Participation
None of our executive officers currently serves, or in the past year has served, as a member of the board of directors or compensation committee (or other board committee performing equivalent functions) of any entity that has one or more of its executive officers serving on our board of directors or compensation committee.
REPORT OF THE COMPENSATION COMMITTEE
The compensation committee has reviewed and discussed the Compensation Discussion and Analysis section of the Company’s annual report on Form 10-K with management, and based on the compensation committee’s review and discussion with management, the compensation committee recommended that the Compensation Discussion and Analysis section be included in the Company’s annual report on Form 10-K for fiscal year 2017.
Submitted by the compensation committee:
Goh Yong Siang
Ong Tiong Sin
Domenic J. Dell’Osso, Jr.
Item 12.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
The following table sets forth information regarding beneficial ownership of our shares of common stock as of March 7, 2018 by:
· each person, or group of affiliated persons, known by us to beneficially own more than 5% of our common stock;
· each of our directors;
· our named executive officers; and
· all of our current executive officers and directors as a group.
We have determined beneficial ownership in accordance with the rules of the SEC and the information is not necessarily indicative of beneficial ownership for any other purpose. Under these rules, beneficial ownership includes any shares as to which the individual or entity has sole or shared voting power or investment power. Applicable percentage ownership is based on 109,274,564 shares of common stock outstanding as of March 7, 2018.
This table is based upon information supplied by our executive officers, directors and each person, or group of affiliated persons, known by us to beneficially own more than 5% of our common stock, and the Section 13 filings with the SEC. Unless otherwise indicated below, to our knowledge, the persons and entities named in the table have sole voting and sole investment power with respect to all shares that they beneficially own, subject to community property laws where applicable.
* Represents beneficial ownership of less than one percent
(1) Maju Investments (Mauritius) Pte Ltd is wholly owned by Fullerton Fund Investments Pte Ltd, which is wholly owned by Temasek.
(2) On February 1, 2018, the Company entered into an investors’ rights agreement with Maju and Chesapeake. Pursuant to the investors’ rights agreement, Maju and Chesapeake may be deemed to have formed a group pursuant to Rule 13d-5(b)(1) of the Exchange Act. Such group could be deemed to have beneficial ownership, for purposes of Sections 13(d) and 13(g) of the Exchange Act, of all equity securities of the Company beneficially owned by such parties. Such parties would, as of March 7, 2018 be deemed to beneficially own an aggregate of 63,615,933 shares (58.2%) of our capital stock. Each stockholder party to the investors’ rights agreement disclaims beneficial ownership of any shares of our common stock owned by the other stockholder party to the agreement.
(3) CHK Energy Holdings, Inc. is a subsidiary of Chesapeake Energy Corporation.
(4) Senja Capital Ltd is wholly owned by RRJ Capital Master Fund I, L.P., the general partner of which is RRJ Capital Limited.
(5) On February 1, 2018 the Company entered into an investors’ rights agreement with Senja and Hampton. Pursuant to the investors’ rights agreement, Senja and Hampton may be deemed to have formed a group pursuant to Rule 13d-5(b)(1) of the Exchange Act. Such group could be deemed to have beneficial ownership, for purposes of Sections 13(d) and 13(g) of the Exchange Act, of all equity securities of the Company beneficially owned by such parties. Such parties would, as of March 7,
2018 be deemed to beneficially own an aggregate of 13,340,226 shares (12.2%) of our capital stock. Each stockholder party to the investors’ rights agreement disclaims beneficial ownership of any shares of our common stock owned by the other stockholder party to the agreement.
(6) RRJ Capital Limited’s board of directors, consisting of Ong Tiong Sin, Ong Tiong Boon, Eddie Teh Ewe Guan, Rizal Bin Ishak and Kim Young So, exercises voting and investment power over these shares.
(7) Hampton Asset Holding Ltd. is wholly owned by Ong Tiong Sin.
(8) Ong Tiong Sin, sole shareholder and sole director of Hampton Asset Holding Ltd., has sole voting and investment power over these shares.
(9) Mr. Dell’Osso is the Executive Vice President and Chief Financial Officer of Chesapeake Parent, and Mr. Lemmerman is the Vice President-Business Development at Chesapeake Parent.
(10) Mr. Ong is the founder and Chief Executive Officer of RRJ Capital Limited, and sole shareholder and sole director of Hampton Asset Holding Ltd., and disclaims beneficial ownership of any shares owned directly or indirectly by Senja Capital Ltd, except to the extent of his pecuniary interest therein. As such, the shares attributed to Mr. Ong represent a sum of the shares beneficially owned by Senja Capital Ltd and Hampton Asset Holding Ltd.
Equity Compensation Plan Information
(1) Includes an aggregate of restricted stock units that were not vested as of December 31, 2017 under the 2014 LTIP. The numbers are before adjustment for the 69.258777:1 reverse stock split that occurred in February 2018 prior to the IPO. The restricted stock units vested immediately before the effectiveness of the registration statement on February 1, 2018 and were settled in cash.
(2) Only restricted stock units have been granted under the 2014 LTIP; there is no weighted average exercise price associated with these awards.
(3) Represents shares of common stock authorized for issuance under the 2014 LTIP in connection with awards of stock options, share appreciation rights, restricted shares, restricted share units, performance shares, performance units, dividend equivalents and other share-based award.
Item 13.
Item 13. Certain Relationships and Related Transactions, and Director Independence
The following is a summary of transactions that occurred on or were in effect after January 1, 2017 that we have been a party and which the amount involved exceeded $120,000 and in which any of our executive officers, directors or beneficial holders of more than 5% of our capital stock had or will have a direct or indirect material interest.
Transactions with Chesapeake
Chesapeake is one of our largest stockholders and is a wholly owned subsidiary of one of our customers, Chesapeake Parent. We recognized revenue from Chesapeake Parent for well-completion services in the amount of $32.1 million, $2.5 million and $113.1 million for the years ended December 31, 2015, 2016 and 2017, respectively.
We are party to a master service agreement dated July 9, 2012, and a master commercial agreement dated December 24, 2016, with subsidiaries of Chesapeake Parent. These agreements govern the performance of services and the supply of materials or equipment to Chesapeake Parent, the specific terms of which are addressed in subsequent written purchase or work orders. These agreements contain standard terms and provisions, including insurance requirements and confidentiality obligations and allocates certain operational risks through indemnity provisions.
Stockholders Agreement
In September 2012, we entered into an amended and restated stockholders agreement with Maju, Senja, Chesapeake, and other stockholders party thereto, as amended in November 2012, April 2014, June 2015, November 2015 and September 2016. The amended and restated stockholders agreement contains agreements among our stockholders regarding, among other things, transfer restrictions, tag along rights, drag along rights, right of first offer, preemptive rights and director nomination and information rights. Prior to completion of the IPO, the amended and restated stockholders agreement was terminated.
Investors’ Rights Agreements
On February 1, 2018, the Company entered into an investors’ rights agreement with Maju and Chesapeake, pursuant to which we will be required to take all necessary action for individuals designated by Maju and Chesapeake to be included in the slate of nominees recommended by the board of directors for election by our stockholders. Under the investors’ rights agreement, each of Maju and Chesapeake have the right to nominate (1) two directors so long as it beneficially owns at least 15% of our then-outstanding shares of capital stock or (2) one director so long as it beneficially owns at least 5% but less than 15% of our then-outstanding shares of capital stock. The investors’ rights agreement also provides that so long as Maju or Chesapeake beneficially owns at least 5% of our then-outstanding shares of capital stock, it may elect to designate one non-voting observer to attend all meetings of the board of directors and committees of the board of directors. The investors’ rights agreement also provides Maju or Chesapeake with certain information rights for so long as it beneficially owns at least 5% of our then-outstanding shares of common stock. Each of Maju and Chesapeake have agreed to take all reasonable actions, including voting or providing a consent or proxy, to ensure the election of their respective nominees and other terms of the investors’ rights agreement.
Under the investors’ rights agreement, Maju and Chesapeake may designate its nominee director to be a member of each committee, subject to compliance with applicable stock exchange requirements. The investors’ rights agreement restricts our ability to adopt a shareholder rights plan and similar arrangements or to become subject to the provisions of Section 203 of the DGCL without the consent of Maju and Chesapeake. The agreement also grants other consent rights to Maju and Chesapeake, including for charter and bylaw provisions inconsistent with the investors’ rights agreement.
The investors’ rights agreement with Maju and Chesapeake provides that (1) we renounce any interest in any business opportunities of Chesapeake and Maju, their affiliates and directors nominated by them, and that none of the foregoing have any obligation to offer or present us those opportunities or any related information or to use any information regarding other or competing business for us, (2) we acknowledge our prior and future agreements and transactions with Chesapeake and its affiliates and (3) we waive any claims or recourse relating to the foregoing matters.
On February 1, 2018, the Company entered into an investors’ rights agreement with Senja and Hampton, pursuant to which, the Company is required to take all necessary action for the individual collectively designated by Senja and Hampton to be included in the slate of nominees recommended by the board of directors for election by our stockholders. Under the investors’ rights agreement, Senja and Hampton have the right to nominate one director so long as they collectively with their affiliates own at least 5% of our then-outstanding shares of capital stock. The investors’ rights agreement also provides that so long as Senja and Hampton collectively with their affiliates own at least 5% of our then-outstanding shares of capital stock, they may elect to designate one non-voting observer to attend all meetings of the board of directors and committees of the board of directors. The investors’ rights agreement also provides Senja and Hampton with certain information rights for so long as they collectively with their affiliates own at least 5% of our then-outstanding shares of capital stock. The agreement also grants other rights to Senja and Hampton, including consent rights for charter and bylaw provisions inconsistent with the investors’ rights agreement.
The investors’ rights agreement with Senja and Hampton will provide that (1) we renounce any interest in any business opportunities of Senja and Hampton, their affiliates and directors nominated by them, and that none of the foregoing have any obligation to offer or present us those opportunities or any related information or to use any information regarding other or competing business for us and (2) we waive any claims or recourse relating to the foregoing matters.
Senja is wholly owned by RRJ Capital Master Fund I, L.P. RRJ is the general partner of RRJ Capital Master Fund I, L.P. RRJ’s board of directors, which consists of Ong Tiong Sin, Ong Tiong Boon, Eddie Teh Ewe Guan, Rizal Bin Ishak and Kim Young
So, exercises voting and investment power over our shares held by Senja. Further, Mr. Ong, Senja’s board designee on our board of directors is also the sole shareholder and sole director of Hampton.
Registration Rights Agreement
On February 1, 2018, the Company entered into a registration rights agreement with Maju, Chesapeake, Senja and Hampton. Under the terms of the registration rights agreement, the parties may request registration, or a demand registration, of all or a portion of their common stock, or Registrable Shares, under the Securities Act. We will not be obligated to effectuate more than four demand registrations for each of Maju and Chesapeake, and more than four demand registrations for Senja and Hampton collectively. Any demand registration must be for an anticipated aggregate offering price of at least $50.0 million. In addition, in the event we register additional shares of common stock for sale to the public, we will be required to give notice of the registration to the parties to the registration rights agreement and, subject to certain limitations, include shares of common stock held by them in the registration. The agreement includes customary indemnification and contribution provisions in favor of the parties to the agreement against certain losses and liabilities arising out of or based upon any filing or other disclosure made by us under securities laws relating to such registration. In addition, each stockholder that has registration rights pursuant to this agreement will agree not to sell, otherwise dispose of any securities, or exercise registration rights without the prior written consent of the underwriters for a period of 180 days after the date of the IPO, subject to certain customary exceptions, terms and conditions. We will generally pay all registration expenses in connection with our registration obligations.
Procedures for Approval of Related Party Transactions
Pursuant to our amended and restated audit committee charter, our audit committee has the primary responsibility for reviewing and approving or disapproving “related-party transactions,” which are transactions between us and related persons in which the aggregate amount involved exceeds or may be expected to exceed $120,000 and in which a related person has or will have a direct or indirect material interest. Our policy regarding transactions between us and related persons provides that the definition of a related person will include, among others, a director, executive officer, nominee for director or greater than 5% beneficial owner of our common stock, in each case since the beginning of the most recently completed fiscal year, and any of their immediate family members. We have not adopted formal policies and procedures for the review, approval or disapproval of such transactions, but instead review them on a case-by-case basis and will follow the guidance of Section 144 of the Delaware General Corporation Law.
Item 14.
Item 14. Principal Accountant Fees and Services
The following table represents aggregate fees billed to us for the fiscal years ended December 31, 2017 and 2016 by our independent registered public accounting firm, Grant Thornton LLP. All such fees described below were approved by the audit committee.
(1) Audit fees consist of aggregate fees for professional services rendered for the audit of our consolidated financial statements, reviews of our interim consolidated financial statements, services in connection with statutory and regulatory filing requirements and our debt and equity offerings.
(2) Audit-related fees consist of aggregate fees for assurance and related services related to the audit or review of our financial statements that are not reported under “Audit Fees” above.
(3) Tax fees consist of aggregate fees for professional services for tax compliance, tax advice and tax planning, primarily, fees related to tax preparation services.
(4) Other fees consists of amounts billed for services other than those noted above.
Our audit committee has adopted a policy and procedures for the pre-approval of audit and, if applicable, non-audit services rendered by our independent registered public accounting firm.
PART IV
Item 15.
Item 15. Exhibits and Financial Statement Schedules
(a) The following documents are filed as part of this Report:
1. Financial Statements. See Index to Consolidated Financial Statements and Schedules of FTS International, Inc. on page of this Report.
2. Financial Statement Schedules. Schedules are omitted because they are not required or applicable, or the required information is included in the Financial Statement or related notes thereto.
3. Exhibits. The exhibits filed with this Report are set forth in the Exhibit Index.
EXHIBIT INDEX
Exhibit
Number
Description
3.1
***
Amended and Restated Certificate of Incorporation of the Company
3.2
***
Amended and Restated Bylaws of the Company
4.1
***
Indenture, dated as of April 16, 2014, among FTS International, Inc., as issuer, the guarantors named therein and U.S. Bank National Association, as collateral agent and trustee
4.2
***
Indenture, dated as of June 1, 2015, among FTS International, Inc., as issuer, the guarantors named therein and U.S. Bank National Association, as collateral agent and trustee
4.3
***
Registration Rights Agreement
4.4
***
Investors’ Rights Agreement by and among FTS International, Inc., Maju Investments (Mauritius) Pte Ltd and CHK Energy Holdings, Inc.
4.5
***
Investors’ Rights Agreement by and among FTS International, Inc., Senja Capital Ltd and Hampton Asset Holding Ltd.
10.1
***
Term Loan Agreement, dated as of April 16, 2014, among FTS International, Inc., Wells Fargo Bank, National Association, as administrative agent, and other lenders party thereto
10.2
***
Employment Agreement, dated as of December 6, 2014, between FTS International, Inc. and Perry Harris
10.3
***
Severance Agreement, dated as of May 3, 2016, between FTS International, Inc. and Michael J. Doss
10.4
***
Severance Agreement, dated as of May 3, 2016, between FTS International, Inc. and Buddy Petersen
10.5
***
Severance Agreement, dated as of May 3, 2016, between FTS International, Inc. and Lance Turner
10.6
***
Letter Agreement, dated as of August 5, 2015, between FTS International, Inc. and Lance Turner
10.7
***
Letter Agreement, dated as of March 29, 2017, between FTS International, Inc. and Karen D. Thornton
10.8
***
Letter Agreement, dated as of March 29, 2017, between FTS International, Inc. and Jennifer L. Keefe
10.9
***
FTS International, Inc. 2014 Long-Term Incentive Plan
10.10
***
Form of Restricted Stock Unit Agreement (Stock Settled) under the 2014 Long-Term Incentive Plan
10.11
***
Description of 2016 Short-Term Incentive Plan
10.12
***
Description of 2017 Short-Term Incentive Plan
10.13
***
Form of Indemnification Agreement between FTS International, Inc. and each of its directors and executive officers
10.14
***
Master Service Agreement, dated as of July 9, 2012, by and between Chesapeake Operating, Inc. and FTS International Services, LLC
10.15
***
Master Commercial Agreement, dated as of December 24, 2016, by and between Chesapeake Operating, LLC and FTS International Services, LLC
10.16
***
Security Agreement, dated as of April 16, 2014, by and among FTS International, Inc., FTS International Services, LLC, FTS International Manufacturing, LLC and U.S. Bank National Association, as collateral agent
10.17
***
Pari Passu Intercreditor Agreement, dated as of April 16, 2014, among FTS International, Inc., FTS International Services, LLC, FTS International Manufacturing, LLC and U.S. Bank National Association, as collateral agent and Wells Fargo Bank, National Association, in its capacity as administrative agent for the Term Secured Parties (as defined therein)
10.18
***
Junior Lien Intercreditor Agreement, dated as of April 16, 2014, among FTS International, Inc., FTS International Services, LLC, FTS International Manufacturing, LLC, Wells Fargo Bank, National Association in its capacity as administrative agent under the Term Loan Agreement, US Bank National Association, as collateral agent and Wells Fargo Bank, National Association, in its capacity as administrative agent for the ABL Secured Parties (as defined therein)
10.19
***
Junior Lien Intercreditor Agreement Joinder, dated as of June 1, 2015, among FTS International, Inc., FTS International Services, LLC, FTS International Manufacturing, LLC, Wells Fargo Bank, National Association in its capacity as administrative agent under the Term Loan Agreement, US Bank National Association, as collateral agent and Wells Fargo Bank, National Association, in its capacity as administrative agent for the ABL Secured Parties (as defined in the Junior Lien Intercreditor Agreement)
10.20
***
Guaranty and Security Agreement, dated as of April 16, 2014, from FTS International, Inc., FTS International Services, LLC and FTS International Manufacturing, LLC to Wells Fargo Bank, National Association
10.21
***
Amended and Restated Trademark Security Agreement, dated as of June 22, 2015, from FTS International Services, LLC to Wells Fargo Bank, National Association pursuant to the Term Loan Agreement dated April 16, 2014
10.22
***
Amended and Restated Trademark Security Agreement, dated as of June 22, 2015, from FTS International Services, LLC to U.S. Bank National Association pursuant to the Indenture dated April 16, 2014
10.23
***
Amended and Restated Trademark Security Agreement, dated as of June 22, 2015, from FTS International Services, LLC to U.S. Bank National Association pursuant to the Indenture dated June 1, 2015
10.24
***
FTS International, Inc. 2018 Equity and Incentive Compensation Plan
10.25
*
Form of Restricted Stock Unit Agreement under the 2018 Equity and Incentive Compensation Plan
10.26
***
First Amendment to Severance Agreement, dated as of June 15, 2017, between FTS International, Inc. and Michael J. Doss
10.27
***
First Amendment to Severance Agreement, dated as of June 15, 2017, between FTS International, Inc. and Buddy Petersen
10.28
***
First Amendment to Severance Agreement, dated as of June 15, 2017, between FTS International, Inc. and Lance Turner
10.29
***
Letter Agreement, dated as of June 15, 2017, between FTS International, Inc. and Karen D. Thornton
10.30
***
Letter Agreement, dated as of June 15, 2017, between FTS International, Inc. and Jennifer L. Keefe
10.31
***
Credit Agreement, dated February 22, 2018, among FTS International, Inc., Wells Fargo Bank, National Association, as administrative agent, and the several lenders party thereto
10.32
***
Guaranty and Security Agreement, dated February 22, 2018, among FTS International Services, LLC, FTS International, Inc., FTS International Manufacturing, LLC and Wells Fargo Bank, National Association, as administrative agent
10.33
***
Trademark Security Agreement, dated February 22, 2018, between FTS International Services, LLC and Wells Fargo Bank, National Association, as administrative agent
10.34
***
Junior Lien Intercreditor Agreement Joinder, dated as of February 22, 2018, between FTS International, Inc., FTS International Services, LLC, FTS International Manufacturing, LLC, Wells Fargo Bank, National Association in its capacity as administrative agent under the Term Loan Agreement, US Bank National Association, as the notes collateral agent and Wells Fargo Bank, National Association, in its capacity as the ABL Facility Agent (as defined in the Junior Lien Intercreditor Agreement)
10.35
*
Letter Agreement, dated December 19, 2016, between FTS International, Inc. and Karen D. Thornton
10.36
*
Form of Restricted Stock Unit Agreement for Directors under the 2018 Equity and Incentive Compensation Plan
21.1
*
List of Subsidiaries
23.1
*
Consent of Grant Thornton LLP
24.1
*
Power of Attorney (included on signature page)
31.1
*
Certification of Principal Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.2
*
Certification of Principal Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32.1
**
Certification of Chief Executive Officer and Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
* Filed herewith
** Furnished herewith
*** Previously filed
 Management contract, compensatory plan or arrangement
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
FTS INTERNATIONAL, INC.
/s/ Michael J. Doss
Michael J. Doss
March 9, 2018
Chief Executive Officer
POWER OF ATTORNEY
KNOW ALL MEN BY THESE PRESENTS, that each person whose signature appears below hereby constitutes and appoints Michael J. Doss and Jennifer L. Keefe, and each of them, with the full power to act without the other, such person’s true and lawful attorneys-in-fact and agents, with full power of substitution and resubstitution, for him or her and in his or her name, place and stead, in any and all capacities, to sign, execute and file this Annual Report on Form 10-K and any or all amendments thereto, with all exhibits and schedules thereto, and other documents in connection therewith with the Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform each and every act and thing necessary or desirable to be done in and about the premises, as fully to all intents and purposes as he might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or any of them, or their substitute or substitutes, may lawfully do or cause to be done.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
Signature
Title
Date
/s/ Michael J. Doss
Chief Executive Officer and Director
March 9, 2018
Michael J. Doss
(Principal Executive Officer)
/s/ Lance D. Turner
Chief Financial Officer and Treasurer
March 9, 2018
Lance D. Turner
(Principal Financial Officer and
Principal Accounting Officer)
/s/ Goh Yong Siang
Chairman
March 9, 2018
Goh Yong Siang
/s/ Domenic J. Dell’Osso, Jr.
Director
March 9, 2018
Domenic J. Dell’Osso, Jr.
/s/ Bryan J. Lemmerman
Director
March 9, 2018
Bryan J. Lemmerman
/s/ Ong Tiong Sin
Director
March 9, 2018
Ong Tiong Sin
/s/ Boon Sim
Director
March 9, 2018
Boon Sim
/s/ Carol J. Johnson
Director
March 9, 2018
Carol J. Johnson
FTS INTERNATIONAL, INC.
Page
Consolidated Financial Statements
Report of Independent Registered Public Accounting Firm
Consolidated Statements of Operations
Consolidated Balance Sheets
Consolidated Statements of Cash Flows
Consolidated Statements of Stockholders’ Equity (Deficit)
Notes to Consolidated Financial Statements
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors and Stockholders
FTS International, Inc.
Opinion on the financial statements
We have audited the accompanying consolidated balance sheets of FTS International, Inc. (a Delaware corporation) and subsidiaries (the “Company”) as of December 31, 2017 and 2016, the related consolidated statements of operations, stockholders’ equity (deficit), and cash flows for each of the three years in the period ended December 31, 2017, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2017 and 2016, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017, in conformity with accounting principles generally accepted in the United States of America.
Basis for opinion
These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
/s/ GRANT THORNTON LLP
We have served as the Company’s auditor since 2015.
Dallas, Texas
March 9, 2018
FTS INTERNATIONAL, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
The accompanying notes are an integral part of these consolidated financial statements.
FTS INTERNATIONAL, INC.
CONSOLIDATED BALANCE SHEETS
The accompanying notes are an integral part of these consolidated financial statements.
FTS INTERNATIONAL, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
The accompanying notes are an integral part of these consolidated financial statements.
FTS INTERNATIONAL, INC.
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY (DEFICIT)
The accompanying notes are an integral part of these consolidated financial statements.
FTS INTERNATIONAL, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1 - DESCRIPTION OF BUSINESS
Throughout the notes to these consolidated financial statements, the terms “FTSI,” “we,” “us,” “our” or “ours” refer to FTS International, Inc., together with its consolidated subsidiaries.
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 (“E&P”), companies in shale and other unconventional resource formations. Our customers include Chesapeake Energy Corporation, ConocoPhillips, Devon Energy Corporation, EOG Resources, Inc., Diamondback Energy, Inc., EQT Company, Range Resources Corporation, and other leading E&P companies that specialize in unconventional oil and natural gas resources in North America. We are one of the top three hydraulic fracturing providers across our operating footprint, which consists of 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. Substantially all of our business activities support our well completion services. We manage our business, allocate resources, and assess our financial performance on a consolidated basis; therefore we do not have separate operating segments.
In 2014, we entered into a 15-year joint venture agreement with the Sinopec Group (“Sinopec”). This joint venture collaboration offers hydraulic stimulation services in China. The joint venture company, SinoFTS Petroleum Services Ltd. (“SinoFTS”), is owned 55% by Sinopec and 45% by us. SinoFTS will serve both Sinopec and other exploration and production companies throughout China. SinoFTS began performing hydraulic fracturing services in China in 2016.
Recent Developments: In February 2018 the Company completed an initial public offering of its common stock and completed a number of other transactions. See Note 17 - “Subsequent Events” for more information.
Concentrations of Risk
Our business activities are concentrated in the well completion services segment of the oilfield services industry in the United States. The market for these services is cyclical, and we depend 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 predominantly influenced by current and expected prices for oil and natural gas. Historically, a low commodity-price environment has caused our customers to significantly reduce their hydraulic fracturing activities and the prices they are willing to pay for those services. During these periods, these customer actions materially adversely affected our business, financial condition and results of operations.
Our customer base has historically been concentrated. 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 paying, us significant amounts of our outstanding receivables. The following table shows the customers who represented more than 10% of our total revenue in any one of the periods indicated below:
* Less than 10%
Related Parties
We have historically provided services and sold equipment to Chesapeake Energy Corporation and its affiliates (“Chesapeake”), which beneficially owned approximately 30% of our outstanding common stock and had the right to designate two individuals to serve on our board of directors during the periods presented. Revenue earned from Chesapeake was $113.1 million, $2.4 million and $32.1 million in 2017, 2016 and 2015, respectively. All revenue earned from Chesapeake is based on the prevailing
market prices for our services at the time the work is performed. At December 31, 2017 and 2016, we had accounts receivable balances of $2.7 million and zero, respectively, from Chesapeake.
We sold equipment to SinoFTS for $0.3 million, $0.3 million and $11.4 million in 2017, 2016 and 2015, respectively. All revenue earned from SinoFTS is based on prevailing market prices. At December 31, 2017 and 2016, we had accounts receivable balances of $0.3 million and $0.1 million, respectively, from this related party.
NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Basis of Presentation
We prepared the consolidated financial statements in accordance with accounting principles generally accepted in the United States of America (“GAAP”). The consolidated financial statements include the accounts of FTSI and all majority-owned domestic and foreign subsidiaries. Investments over which we have the ability to exercise significant influence over operating and financial policies, but do not hold a controlling interest, are accounted for using the equity method of accounting. All significant intercompany accounts and transactions have been eliminated in consolidation. There were no items of other comprehensive income in the periods presented.
Use of Estimates
The preparation of financial statements in accordance with GAAP requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities, related revenues and expenses, and the disclosure of gain and loss contingencies at the date of the financial statements and during the periods presented. We base these estimates on historical results and various other assumptions believed to be reasonable, all of which form the basis for making estimates concerning the carrying values of assets and liabilities that are not readily available from other sources. Actual results could differ materially from those estimates.
Cash and Cash Equivalents
Cash equivalents include only investments with an original maturity of three months or less. We occasionally hold cash deposits in financial institutions that exceed federally insured limits. We monitor the credit ratings and our concentration of risk with these financial institutions on a continuing basis to safeguard our cash deposits.
Accounts Receivable and Allowance for Doubtful Accounts
Accounts receivable are recorded at their invoiced amounts. We establish an allowance for doubtful accounts to reduce the carrying value of our accounts receivable based on a number of factors, including the length of time that accounts receivable are past due, our previous loss history, and the customer’s creditworthiness. The provision for doubtful accounts was not significant for any period presented in the Consolidated Statements of Operations.
Inventories
Inventories consist of proppants and chemicals that are used to provide hydraulic fracturing services, maintenance parts that are used to service our hydraulic fracturing equipment, and explosives and perforating guns that are used to provide our wireline services. Proppants generally consist of raw sand, resin-coated sand or ceramic particles. Inventories are stated at the lower of cost or market value. The cost basis of our inventories is based on the average cost method and includes in-bound freight costs.
As necessary, we record an adjustment to decrease the value of slow moving and obsolete inventory to its net realizable value. To determine the adjustment amount, we regularly review inventory quantities on hand and compare them to estimates of future product demand, market conditions, production requirements and technological developments.
Restricted Cash
We have pledged cash as collateral for letters of credit issued to our casualty and general liability insurance provider. Restricted cash totaled $9.1 million at both December 31, 2017 and 2016, and is included in prepaid expenses and other current assets in our Consolidated Balance Sheets. These amounts represent cash used to secure certain letters of credit. In February 2018, we closed on a new revolving credit facility, and issued replacement letters of credit under the new facility, which allowed us to cancel the cash secured letters of credit.
Property, Plant, and Equipment
Property, plant, and equipment is stated at cost less accumulated depreciation, which is generally provided by using the straight-line method over the estimated useful lives of the individual assets. We manufacture our hydraulic fracturing units and the cost of this equipment, which includes direct and indirect manufacturing costs, is capitalized and carried as construction-in-progress until it is completed. Expenditures for renewals and betterments that extend the lives of our service equipment, which includes the replacement of significant components of service equipment, are capitalized and depreciated. Other repairs and maintenance costs are expensed as incurred.
We capitalize qualifying costs related to the acquisition or development of internal-use software. Capitalization of costs begins after the conceptual formulation stage has been completed. Capitalized costs are amortized over the estimated useful life of the software, which ranges between three and five years. The unamortized balance of capitalized software costs at December 31, 2017 and 2016, was $7.5 million and $12.6 million, respectively. Amortization of computer software was $5.3 million, $5.7 million and 5.4 million in 2017, 2016 and 2015, respectively.
Goodwill and Intangible Assets
Goodwill is the amount by which the consideration transferred to acquire a business exceeds the fair value of the underlying individual assets and liabilities of that business. Goodwill and intangible assets with indefinite lives are not amortized. At December 31, 2017 and 2016, the amount of goodwill recorded in our Consolidated Balance Sheets was zero. Intangible assets with definite lives are amortized on a basis that reflects the pattern in which the economic benefits of the intangible assets are realized, which is generally on a straight-line basis over the asset’s estimated useful life. At December 31, 2017 and 2016, the amount of intangible assets with definite lives recorded in our Consolidated Balance Sheets was zero after giving effect to an impairment of $475.5 million during the year ended December 31, 2015.
Impairment of Long-Lived Assets, Goodwill and Other Intangible Assets
Long-lived assets, such as property, plant, equipment and definite-lived intangible assets, are reviewed for impairment when events or changes in circumstances indicate that the carrying value of the asset may not be recoverable. Recoverability is assessed based on the undiscounted future cash flows generated by the asset. If the carrying amount of an asset is not recoverable, we recognize an impairment loss equal to the amount by which the carrying amount exceeds fair value. We estimate fair value based on the income, market, or cost valuation techniques.
Goodwill and intangible assets with indefinite lives are reviewed at least annually for impairment, and in interim periods if certain events occur indicating that the carrying value of goodwill or intangible assets may be impaired. We estimate fair values utilizing valuation methods such as discounted cash flows and comparable market valuations. We perform our annual impairment tests at the beginning of the fourth quarter.
Equity Method Investments
Investments in which we have the ability to exercise significant influence, but not control, are accounted for pursuant to the equity method of accounting. We recognize our proportionate share of earnings or losses of our affiliates three months after they occur. When events and circumstances warrant, investments accounted for under the equity method of accounting are evaluated for impairment. An impairment charge is recorded whenever a decline in value of an investment below its carrying amount is determined to be other-than-temporary.
Income Taxes
Income taxes are accounted for using the asset and liability method. Deferred taxes are recognized for the tax consequences of temporary differences by applying enacted statutory tax rates applicable to future years to differences between the financial statement carrying amounts and the tax bases of existing assets and liabilities. The effect on deferred taxes of a change in tax rates is recognized in income in the period that includes the enactment date. We recognize future tax benefits to the extent that such benefits are more likely than not to be realized.
We record a valuation allowance to reduce the value of a deferred tax asset if based on the consideration of all available evidence, it is more likely than not that all or some portion of the deferred tax asset will not be realized. Significant weight is given to evidence that can be objectively verified. We evaluate our deferred income taxes quarterly to determine if a valuation allowance is required by considering all available evidence, including historical and projected taxable income and tax planning strategies. Any deferred tax asset subject to a valuation allowance is still available to us to offset future taxable income, subject to annual limitations
in the event of an “ownership change” under Section 382 of the Internal Revenue Code. We will adjust a previously established valuation allowance if we change our assessment of the amount of deferred income tax asset that is more likely than not to be realized.
Revenue Recognition
We recognize revenue when we have the right to invoice a customer under our contracts, which is generally upon the completion of a fracturing stage. We typically complete one or more stages per day. A stage is considered complete when we have met the specifications set forth by the customer, at which time the customer is obligated to pay us for the services rendered. The price for our services is agreed to with our customer for each stage completed. The price for our services typically includes an equipment charge and product charges for proppant, chemicals and other products actually consumed during the course of providing our services. The amount invoiced to our customer for a completed stage is not dependent upon the completion of any other stages.
In certain customer arrangements, we are guaranteed a minimum monthly amount of compensation in exchange for us providing exclusive use of a fracturing fleet to the customer. Under these arrangements, the amount invoiced to our customer for services performed is not dependent upon any future event.
Unconditional Purchase Obligations
We have historically entered into supply arrangements with our vendors, primarily for sand, that contain unconditional purchase obligations. These represent obligations to transfer funds in the future for fixed or minimum quantities of goods or services at fixed or minimum prices, such as “take-or-pay” contracts. We enter into these unconditional purchase obligation arrangements in the normal course of business to ensure that adequate levels of sourced product are available to us. To account for these arrangements, we must monitor whether we may be required to make a minimum payment to a vendor in a future period because our projected inventory purchases may not satisfy our minimum commitments. If we conclude that it is probable that we will make a minimum payment under these arrangements, we will record an estimated loss for these commitments in the current period.
Stock-Based Compensation
We measure all employee stock-based compensation awards using a fair value method and record this cost in the consolidated financial statements. Our stock-based compensation relates to restricted stock awards or restricted stock units issued to our employees. On the date that an equity-classified award is granted, we determine the fair value of the award and recognize the compensation cost over the requisite service period, which typically is the period over which the award vests. For liability-classified awards, we determine the fair value of the award at each reporting date and recognize a portion of the fair value equal to the amount of time that has passed in the requisite service period. For stock-based awards with graded vesting based solely on the satisfaction of a service condition, we recognize compensation cost as a single award on a straight-line basis. We account for forfeited awards as forfeitures occur, which results in a reversal of stock-based compensation cost previously recognized up to the date of the forfeiture. For stock-based awards with performance conditions that affect vesting, we only recognize compensation cost when it is probable that the performance conditions will be met.
Fair Value Measurements
Fair value is defined as the price that would be received from selling an asset or paid to transfer a liability in an orderly transaction between market participants at a measurement date. We apply the following fair value hierarchy, which prioritizes the inputs used to measure fair value into three levels and bases the categorization within the hierarchy upon the lowest level of input that is available and significant to the fair value measurement:
· Level One: The use of quoted prices in active markets for identical financial instruments.
· Level Two: The use of quoted prices for similar instruments in active markets or quoted prices for identical or similar instruments in markets that are not active or other inputs that are observable in the market or can be corroborated by observable market data.
· Level Three: The use of significantly unobservable inputs that typically require the use of management’s estimates of assumptions that market participants would use in pricing.
New Accounting Standards Updates
In May 2014, the Financial Accounting Standards Board (“FASB”), issued Accounting Standards Update (“ASU”), 2014-09, Revenue from Contracts with Customers. The FASB has subsequently issued a number of additional ASUs to update this guidance. This guidance will supersede substantially all existing accounting guidance related to the accounting for revenue transactions. This
guidance establishes a core principle that an entity should record revenue when it transfers control of goods or services to customers at an amount that reflects the consideration to which it expects to be entitled in exchange for those goods or services. We have substantially completed the process of determining the effects that the new standard will have on our consolidated financial statements. Our approach included performing a review of key contracts and comparing historical accounting policies and practices to the new accounting guidance. Based on our assessment, we expect the adoption of this ASU to have an immaterial effect on our current revenue recognition process. We will reflect this standard in our consolidated financial statements beginning on January 1, 2018, utilizing the modified retrospective method. We do not expect to record a cumulative effect of accounting change upon adoption.
In February 2016, the FASB issued ASU 2016-02, Leases. This standard was issued to increase transparency and comparability among organizations by requiring that most leases be included on the balance sheet and by expanding disclosure requirements. This standard is scheduled to be effective for our financial statements beginning on January 1, 2019. We are in the process of determining the effects that the new standard will have on our consolidated financial statements. Our approach includes a review of existing leases and other executory contracts that may contain embedded leases and identifying the key terms that will be necessary for us to calculate the right-of-use asset and corresponding lease liability. Based upon our expected future lease payments on existing leases that are longer than twelve months, we expect that the adoption of this standard will have a material effect on our total assets and total liabilities; however, we have not yet completed the quantification of the amount of the change.
In August 2016, the FASB issued ASU 2016-15, Classification of Certain Cash Receipts and Cash Payments. This standard was issued to reduce the diversity in practice in how certain cash receipts and cash payments are presented and classified in the statement of cash flows. This standard is scheduled to be effective for our financial statements beginning on January 1, 2018. We adopted this standard on January 1, 2018, and expect it to have no effect on our statements of cash flows.
In November 2016, the FASB issued ASU 2016-18, Restricted Cash. This standard was issued to change the presentation of amounts generally described as restricted cash and restricted cash equivalents to be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows. This standard is scheduled to be effective for our financial statements beginning on January 1, 2018, and we adopted the standard on that date. Restricted cash is classified as prepaid expenses and other current assets on our consolidated balance sheets and totaled $9.1 million at both December 31, 2017 and 2016. These amounts represent cash used to secure certain letters of credit. In February 2018, we closed on a new revolving credit facility, and issued replacement letters of credit under the new facility, which allowed us to cancel the cash secured letters of credit.
NOTE 3 - SUPPLEMENTAL BALANCE SHEET INFORMATION
Accounts Receivable
The following table summarizes our accounts receivable balance:
The change in allowance for doubtful accounts is as follows:
Inventories
The following table summarizes our inventories:
Prepaid Expenses and Other Current Assets
The following table summarizes our prepaid expenses and other current assets:
Property, Plant, and Equipment, net
The following table summarizes our property, plant, and equipment:
Depreciation expense was $86.6 million, $112.6 million and $169.9 million in 2017, 2016 and 2015, respectively.
Accrued Expenses and Other Current Liabilities
The following table summarizes our accrued liabilities:
NOTE 4 - GOODWILL AND OTHER INTANGIBLE ASSETS
Goodwill
The changes in the carrying amount of goodwill were as follows for the year ended December 31, 2015. There was no activity during 2016 or 2017.
In connection with our 2014 wireline acquisition, we agreed to pay up to $12.5 million of contingent cash consideration in each of 2015 and 2016 based on the achievement of earnings targets. The final fair value of this contingent consideration at the acquisition date was $3.4 million. We were required to measure the fair value of the contingent consideration at each reporting date. The fair value of the contingent consideration was zero at both December 31, 2015 and 2016. The decrease in the fair value of the contingent consideration was due to reduced actual and forecasted cash flows for this reporting unit during the earn-out periods. These fair values were based on the use of unobservable inputs and are classified as Level 3 in the FASB’s fair value hierarchy.
The reduced actual and forecasted cash flows at June 30, 2015, were an indicator that we should conduct an interim goodwill impairment test for our wireline reporting unit in the second quarter of 2015. As a result of this test, we recorded a non-cash impairment of $7.1 million in the second quarter of 2015. We estimated the fair value using the income approach. The significant inputs employed in determining fair value included, but were not limited to, projected financial information, growth rates, terminal value, and discount rates. This fair value was based on the use of unobservable inputs and is classified as Level 3 in the FASB’s fair value hierarchy.
Other Intangible Assets
The following table summarizes our other intangible assets and accumulated amortization:
Our tradename has an indefinite life and, therefore, is not amortized. For our definite-lived intangible assets, the weighted-average amortization periods prior to the impairments in 2015 were ten years for customer relationships and five years for proprietary chemical blends. In the fourth quarter of 2015 we impaired all of our customer relationships and proprietary chemical blends. See Note 9 - “Impairments and Other Charges” for more discussion of our 2015 impairments.
Amortization for definite-lived intangible assets was $102.5 million in 2015. Estimated amortization expense, excluding any future acquisitions, for each of the next five years is zero due to the impairments recorded in 2015.
NOTE 5 - DEBT
The following table summarizes our long-term debt:
Estimated fair values for our term loan and senior notes were determined using recent trading activity and/or bid-ask spreads and are classified as Level 2 in the FASB’s fair value hierarchy.
2020 Senior Floating Rate Notes
On June 1, 2015, we completed an offering of $350 million of senior secured floating rate notes due June 15, 2020, in a private offering to qualified institutional buyers (“2020 Senior Notes”). The 2020 Senior Notes bear interest at a three-month London Interbank Offered Rate (“LIBOR”) plus a margin of 7.5% per annum. Interest is payable quarterly, in arrears, on March 15, June 15, September 15 and December 15.
The 2020 Senior Notes were issued at a discount of $3.5 million for aggregate consideration of $346.5 million and resulted in net proceeds to the Company of $340.5 million after debt issuance costs of $6.0 million.
The obligation to pay principal and interest on the 2020 Senior Notes is jointly and severally guaranteed on a full and unconditional basis by all of our wholly owned domestic subsidiaries. The 2020 Senior Notes are secured on a first priority basis by our accounts receivable, inventory, deposit accounts, and certain hydraulic fracturing and other equipment. The 2020 Senior Notes are secured on a second priority basis by 100% of the equity interests of our existing and future domestic subsidiaries and 65% of the voting equity interests of our existing and future foreign subsidiaries.
The 2020 Senior Notes are redeemable, at our option, beginning on June 15, 2016, at a premium of 3%. The redemption premium then declines each year until June 15, 2018, at which time we may redeem the notes at par value.
The 2020 Senior Notes contain covenants that could, in certain circumstances, limit our ability to issue additional debt, repurchase or pay dividends on our common or preferred stock, sell substantially all of our assets, make certain investments, or enter into certain other transactions.
In 2017, we repaid $60.0 million of aggregate principal amount of 2020 Senior Notes. We recognized a loss on debt extinguishment of $1.8 million.
We were in compliance with all of the covenants in the indenture governing our 2020 Senior Notes at December 31, 2017 and 2016.
On February 22, 2018, we repaid the remaining principal amount of the 2020 Senior Notes. See Note 17 - “Subsequent Events” for more information.
2022 Senior Notes
On April 16, 2014, we completed an offering of $500 million of 6.25% senior secured notes due May 1, 2022, in a private offering to qualified institutional buyers (“2022 Senior Notes”). Interest is payable semiannually, in arrears, on May 1 and November 1. The Company received net proceeds of $489.7 million after debt issuance costs of $10.3 million.
The obligation to pay principal and interest on the 2022 Senior Notes is jointly and severally guaranteed on a full and unconditional basis by all of our wholly owned domestic subsidiaries. The 2022 Senior Notes are secured on a first priority basis by 100% of the equity interests of our existing and future domestic subsidiaries and 65% of the voting equity interests of our existing and
future foreign subsidiaries. The 2022 Senior Notes are secured on a second priority basis by our accounts receivable, inventory, and deposit accounts, which also secure our 2020 Senior Notes as discussed above. All security requirements for the 2022 Senior Notes will cease upon the full repayment of our $550 million term loan discussed below.
The 2022 Senior Notes are redeemable, at our option, beginning on May 1, 2017, at a premium of approximately 4.7%. The redemption premium then declines each year until May 1, 2020, at which time we may redeem the notes at par value.
The 2022 Senior Notes contain covenants that could, in certain circumstances, limit our ability to issue additional debt, repurchase or pay dividends on our common or preferred stock, sell substantially all of our assets, make certain investments, or enter into certain other transactions.
In 2017, we repurchased $17.3 million of aggregate principal amount of 2022 Senior Notes in the qualified institutional market. We recognized a gain on debt extinguishment of $0.4 million. In 2016, we repurchased $43.7 million of aggregate principal amount of 2022 Senior Notes in the qualified institutional market. We recognized a gain on debt extinguishment of $25.4 million.
We were in compliance with all of the covenants in the indenture governing our 2022 Senior Notes at December 31, 2017 and 2016.
Term Loan
On April 16, 2014, we entered into a $550 million term loan, which matures on April 16, 2021, (“Term Loan”) with a group of lenders with Wells Fargo Bank, N.A., as administrative agent. The Term Loan bears interest at LIBOR plus a margin of 4.75% per annum, with a 1.00% LIBOR floor. Interest is payable on interest rate reset dates, which generally will be on a three-month basis.
The Term Loan was issued at a discount of $2.7 million for aggregate consideration of $547.3 million and resulted in net proceeds to the Company of $540.0 million after debt issuance costs of $7.3 million.
The obligation to pay principal and interest on the Term Loan is jointly and severally guaranteed on a full and unconditional basis by all of our wholly owned domestic subsidiaries. The Term Loan is secured on the same basis as the 2022 Senior Notes as discussed above.
The Term Loan contains substantially the same covenants as the 2022 Senior Notes and the 2020 Senior Notes. None of the Term Loan, the 2022 Senior Notes, or the 2020 Senior Notes contain maintenance financial covenants.
In 2016, we repaid $49.0 million of aggregate principal amount of Term Loan. We recognized a gain on debt extinguishment of $28.3 million.
We were in compliance with all of the covenants in the Term Loan at December 31, 2017 and 2016.
Revolving Credit Facility
On April 16, 2014, we entered into a five-year, $200 million revolving credit facility with a group of lenders and Wells Fargo Bank, N.A., as administrative agent. In connection with the issuance of the 2020 Senior Notes, we repaid all amounts outstanding under, and terminated, this revolving credit facility in 2015. We incurred a loss of $1.7 million, which primarily related to the write-off of deferred issuance costs, in connection with the termination of the revolving credit facility. This amount is classified as “Gain or loss on extinguishment of debt, net” on our Consolidated Statements of Operations.
The following table summarizes the maturities of our long-term debt at December 31, 2017:
NOTE 6 - CONVERTIBLE PREFERRED STOCK
In September 2012, we issued and sold 350,000 shares of Series A convertible preferred stock, par value $0.01 per share (the “Preferred Stock”), to certain of our then existing common stockholders. The Preferred Stock was sold for aggregate consideration of $350 million, and resulted in net proceeds to the Company of $349.8 million after the payment of $0.2 million in issuance costs.
Each share of Preferred Stock is convertible into 2,573 shares of our common stock, subject to adjustment upon the occurrence of specified events set forth under terms of the Preferred Stock.
The Preferred Stock is redeemable at the Company’s option at any time after all of our debt has been repaid. The redemption price per share is an amount in cash equal to the original price per share of the Preferred Stock, plus such additional amount as would give the holder an after-tax internal rate of return for investment in the Preferred Stock of 25% per annum (the “Accreted Amount”). At December 31, 2017, the Accreted Amount of the Preferred Stock was estimated to be $1,132.7 million.
The Preferred Stock is mandatorily convertible into shares of our common stock in connection with an initial public offering of our common stock if both of the following conditions are met (a “Qualified IPO”):
· Aggregate proceeds to the Company are at least $250 million; and
· The split-adjusted initial offering price to the public is not less than $1.50 per share.
In connection with a Qualified IPO, each share of Preferred Stock is convertible into the number of shares of common stock that has a market value (based on the initial offering price to the public) equal to the Accreted Amount.
The Preferred Stock is mandatorily redeemable for cash upon a change of control, provided that all of our debt has been repaid. Each share of Preferred Stock will be redeemed for an amount in cash equal to the higher of:
· The Accreted Amount or
· The original purchase price of the Preferred Stock plus an amount equal to 20% of the then outstanding equity value of the Company divided by the number of Preferred Stock shares then outstanding.
The Preferred Stock ranks senior to our common stock with respect to dividend rights and distribution rights in the event of any liquidation, winding-up or dissolution of the Company. The amount that each share of Preferred Stock is entitled to in liquidation is equal to the Accreted Amount.
The holders of the Preferred Stock are also common stockholders of the Company and, prior to the completion of our initial public offering, collectively appointed 100% of our board of directors. Therefore, the Preferred Stock holders could have directed the Company to redeem the Preferred Stock at any time after all of our debt had been repaid; however, we did not consider this to be probable for the periods presented due to the amount of debt outstanding. Therefore, we have classified the Preferred Stock as temporary equity on our Consolidated Balance Sheets but have not recorded any accretion of the Preferred Stock in our consolidated financial statements.
In 2018, the Preferred Stock was converted into new shares of common stock in connection with the completion of an initial public offering of our common stock. See Note 17 - “Subsequent Events” for more information.
NOTE 7 - STOCK-BASED COMPENSATION
Restricted Stock Awards
Historically, certain members of our executive team were granted restricted stock awards. These awards vested at various points in time over vesting periods of up to four years. The most current fair value of one share of our common stock was utilized to determine the fair value of the award on the grant date. The following table summarizes our transactions related to restricted stock awards in 2015. There were no transactions in 2016 or 2017.
(1) The number of units and the fair value per share presented in this table 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 an initial public offering of our common stock. See Note 17 - “Subsequent Events” for more information.
(2) Certain granted but unvested shares are released for tax withholdings on the participant’s behalf.
The total fair value of restricted stock vested in 2015 was $2.4 million. At December 31, 2017 and 2016, there were no unvested restricted stock awards.
Restricted Stock Units
In 2014, our stockholders approved the 2014 Long-Term Incentive Plan (“2014 LTIP”). The 2014 LTIP authorized the grant of up to 55 million restricted stock units (“RSU”) to salaried employees of the Company, as determined by the compensation committee of the board of directors. This plan originally was set to expire on March 3, 2024. The 2014 LTIP allowed for the grant of stock-settled and cash-settled RSUs. The Company had the power to elect, at its sole discretion, to settle any or all of the stock-settled RSUs wholly or partly in cash.
The awards that were granted in 2014 had three vesting conditions: a performance condition based on Company goals, a performance condition based on the occurrence of a qualifying liquidity event such as an initial public offering of our common stock, and a service-period condition. The performance condition was based on Company goals that provided for an upward or downward adjustment to the RSUs granted based on Company performance. The service-period condition provided that 50% of the number of adjusted RSUs vested on each of December 31, 2015, and December 31, 2016.
The following table summarizes the 2017 transactions related to the stock-settled RSUs:
(1) The number of units and the fair value per share presented in this table 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 an initial public offering of our common stock. See Note 17 - “Subsequent Events” for more information.
Under generally accepted accounting principles for stock-based compensation, a performance condition that affects vesting and is based on a corporate liquidity event such as an initial public offering of common stock precludes the recognition of compensation expense related to the awards until this performance condition has been met. Therefore, no compensation expense for these awards will be recognized until this performance condition has been met. At December 31, 2017, there was $1.8 million of total unrecognized compensation cost related to unvested stock-settled RSUs.
The compensation cost charged against income for all stock-based compensation was zero, zero and $1.8 million in 2017, 2016 and 2015, respectively. The total income tax benefit for all stock-based compensation was $0.2 million in 2015; however, such benefit was offset by the valuation allowance against our deferred tax assets.
In February 2018, we completed an initial public offering of our common stock. See Note - 17 “Subsequent Events” for more information. This transaction qualified as the final vesting condition for these RSUs. The Company elected to settle all RSUs on a cash basis. The compensation expense recognized in 2018 for the stock-settled RSUs was $2.0 million. The compensation expense recognized in 2018 for the cash-settled RSUs was $1.7 million. The 2014 LTIP was terminated after the payout of the RSUs.
NOTE 8 - RETIREMENT PLAN
We offer a 401(k) defined contribution retirement plan (“401(k) Plan”), which allows a participant to defer, by payroll deductions, from 0% to 100% of the participant’s annual compensation, limited to certain annual maximums set by the Internal Revenue Code. The 401(k) Plan has historically provided a discretionary matching contribution to each participant’s account. Company matching contributions to the 401(k) Plan are made in cash and were $1.5 million, zero, and $5.5 million in 2017, 2016 and 2015, respectively. The Company suspended matching contributions in July 2015 and resumed making contributions in July 2017.
NOTE 9 - IMPAIRMENTS AND OTHER CHARGES
The following table summarizes our impairments and other charges:
Impairment of Assets and Goodwill
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. During the first nine months of 2015, we recorded a non-cash goodwill impairment of $7.1 million for our wireline reporting unit and an asset impairment of $0.5 million related to real property that we no longer use.
In the fourth quarter of 2015, we concluded that the persistent low commodity price environment and its effect on our current and forecasted cash flows required us to perform multiple asset impairment tests. As a result, we recorded a number of asset impairments in the fourth quarter of 2015.
· We evaluated the long-lived assets of our pressure pumping asset group for impairment and concluded that the fair value of this asset group was lower than the carrying value of the assets in the asset group. We recognized a total impairment for this asset group of $487.0 million. Of this amount, $461.4 million was attributable to our customer relationships, $20.6 million was attributable to certain equipment, and $5.0 million was attributable to our proprietary chemical blends.
· We evaluated the long-lived assets of our wireline asset group for impairment and concluded that the fair value of this asset group was lower than the carrying value of the assets in the asset group. We recognized a total impairment for this asset group of $33.3 million. Of this amount $24.2 million was attributable to certain equipment and $9.1 million was attributable to our customer relationships.
· We evaluated our tradename intangible asset for impairment and concluded that the fair value of this asset was lower than its carrying value, which resulted in an impairment of $30.2 million.
· We recorded $14.8 million of impairments for certain land and buildings that we no longer use.
See Note 14 - “Nonrecurring Fair Value Measurements” for more information on these impairments.
Supply Commitment Charges
We have recorded supply commitment charges related to contractual inventory purchase commitments to certain proppant suppliers. In 2017, 2016 and 2015, we recorded charges under these supply arrangements of $1.2 million, $2.5 million and $11.0 million, respectively. These charges were attributable to our decreased volume of purchases from these suppliers due to our lower activity levels and/or certain customers procuring their own proppants.
While we have successfully worked with our vendors to minimize charges related to these purchase commitments, if industry conditions worsen, if customer requirements for specific types of proppant differ from our contracted supply, or if we are unable to work with our vendors in the future, we may incur supply commitment charges in future periods.
Lease Abandonment Charges
During 2016 and 2015 we vacated certain leased facilities to consolidate our operations. In 2017, 2016 and 2015, we recognized expense of $0.6 million, $2.0 million and $1.8 million, respectively, in connection with these actions.
Employee Severance Costs
During 2016 and 2015, we incurred employee severance costs of $0.8 million and $13.1 million, respectively, in connection with our corporate and operating restructuring initiatives. At December 31, 2016, we had paid substantially all severance payments owed to former employees.
Inventory Write-down
During 2015, we made improvements to our supply chain that reduced our inventory requirements. In connection with this initiative we executed a program to liquidate excess inventory. We recorded a $24.5 million inventory write-down charge in connection with this liquidation program.
Acquisition earn-out adjustments
In 2015, we remeasured the fair value of the contingent consideration related to a wireline acquisition and we recorded adjustments to reduce this liability by $3.4 million. At December 31, 2015 and December 31, 2016, the fair value of the contingent consideration was zero and the period to earn the contingent consideration expired on October 31, 2016.
NOTE 10 - ASSET DISPOSALS
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 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.
NOTE 11 - 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.
NOTE 12 - INCOME TAXES
The following table summarizes the components of income tax expense (benefit):
Actual income tax expense (benefit) differed from the amount computed by applying the statutory federal income tax rate to income (loss) before income taxes as follows:
In December 2017, the President of the United States signed into law the Tax Cuts and Jobs Act of 2017 that, among other things, reduced the federal income tax rate from 35% to 21% beginning on January 1, 2018. Under generally accepted accounting principles for income taxes, we are required to recognize the effects of changes in tax laws and tax rates on deferred tax assets and liabilities in the period in which the new legislation is enacted. Accordingly, we remeasured our federal deferred tax assets as of December 31, 2017, to a 21% rate. This would have resulted in additional tax expense of $424.8 million in 2017; however, this amount has been offset by a corresponding change in our valuation allowance. We are still in the process of evaluating the new foreign tax law provisions that are effective beginning January 2018.
The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities are presented below:
Because of our valuation allowance, our net deferred tax assets are zero and no deferred tax assets or liabilities are included in the Consolidated Balance Sheets.
At December 31, 2017, our federal net operating loss carryforwards were $1.6 billion, which will expire on various dates between 2032 and 2036. At December 31, 2017, our state net operating loss carryforwards were approximately $618 million, which will expire on various dates between 2018 and 2037.
A reconciliation of the valuation allowance for deferred tax assets from January 1, 2015 to December 31, 2017 is as follows:
In 2012, we established a full valuation allowance with respect to our U.S. federal net deferred tax assets and state net deferred tax assets. We have recorded a full valuation allowance for these net deferred tax assets for each year since 2012. Deferred tax assets related to our U.S. federal and state operating losses are still available to us to offset future taxable income, subject to limitations in the event of a change of control under Section 382 of the Internal Revenue Code. At December 31, 2017, we had not incurred such an ownership change.
At each reporting date, we consider all available positive and negative evidence to evaluate whether our deferred tax assets are more likely than not to be realized. A significant piece of negative evidence that we consider is cumulative losses (generally defined as losses before income taxes) incurred in recent years. Such evidence limits our ability to consider other subjective evidence such as our projections for future taxable income. We also concluded that this negative evidence was not overcome by considering other sources of taxable income, which included the reversal of taxable temporary differences and tax-planning strategies.
Since the second quarter of 2017, the Company has been generating taxable income which we will offset with net operating losses incurred in prior years. This represents positive evidence that we may be able to realize some or all of our deferred tax assets; however, we determined that this positive evidence does not yet outweigh the negative evidence of our losses incurred in recent years. For example, at December 31, 2017 and 2016, we had incurred cumulative losses over the most recent three-year periods. If we continue to generate taxable income in 2018, this will be additional positive evidence that we may be able to realize our net deferred tax assets. We will adjust the valuation allowance as we change our assessment of the amount of net deferred tax assets that are more likely than not to be realized; however, due to the negative evidence of our cumulative losses in recent years and the significant cyclicality of our business, we believe that the earliest period when we may adjust the valuation allowance is the fourth quarter of 2018.
A reconciliation of the liability for gross unrecognized income tax benefits (excluding interest) from January 1, 2015 to December 31, 2017 is as follows:
The amount of unrecognized tax benefits that, if recognized, would affect the effective tax rate was zero at December 31, 2017 and 2016, respectively.
We recognize accrued interest and penalties related to any uncertain tax positions as part of the tax provision. At December 31, 2017 and 2016, we had no accrued interest expense associated with unrecognized tax benefits. Interest expense associated with unrecognized tax benefits was $0.1 million in 2015.
FTS International, Inc. and its U.S. subsidiaries join in the filing of a U.S. federal consolidated income tax return. We do not currently have significant operations or undistributed earnings in foreign jurisdictions. Our income tax returns are currently subject to examination in federal and state jurisdictions primarily for tax years from 2014 through 2016.
NOTE 13 - COMMITMENTS AND CONTINGENCIES
Operating Leases
We lease certain administrative and sales offices, operational facilities and office equipment in various cities. We also lease some service equipment and light duty vehicles. Some of our lease agreements include renewal or purchase options that we may choose to exercise at the end of the lease term. Total rental expense under our operating leases was $19.6 million, $19.6 million and $31.7 million in 2017, 2016 and 2015, respectively.
At December 31, 2017, our future minimum rental commitments due under non-cancellable operating leases is summarized below
Purchase Obligations
We have purchase commitments with certain vendors to supply a significant portion of the proppant used in our operations. These agreements have remaining terms ranging from one to seven years. Some of these agreements are take-or-pay agreements with minimum unconditional purchase obligations. These minimum purchase obligations could change based upon the vendors ability to supply a minimum requirement. We also have purchase commitments to a vendor to assist us with the delivery of proppant to our job locations. Total purchases made under these agreements were $46.0 million, $20.9 million and $49.7 million in 2017, 2016 and 2015, respectively. At December 31, 2017, our future minimum purchase commitments due under these agreements is summarized below:
Litigation
In the ordinary course of business, we are subject to various legal proceedings and claims, some of which may not be covered by insurance. Many of these legal proceedings and claims are in early stages, and many of them seek an indeterminate amount of damages. We estimate and provide for potential losses that may arise out of legal proceedings and claims to the extent that such losses are probable and can be reasonably estimated. Significant judgment is required in making these estimates and our final liabilities may ultimately be materially different from these estimates. When preparing our estimates, we consider, among other factors, the progress of each legal proceeding and claim, our experience and the experience of others in similar legal proceedings and claims, and the opinions and views of legal counsel.
In 2012, Continental Industries Group, Inc. (“Continental”) filed two lawsuits against FTS International, Inc. and FTS International Services, LLC in the United States District Court, Southern District of New York that were combined into one action entitled Continental Industries Group, Inc. v. FTS International, Inc. and FTS International Services, LLC. In its suit, Continental claimed that FTSI (a) wrongfully terminated a supply agreement entered into by the parties in 2011, and (b) wrongfully cancelled two alleged purchase orders for the procurement of guar gum, a key component of certain chemicals we utilize in performing our services for customers. Pursuant to the supply agreement, Continental had agreed to enter into a joint venture with a Company in India to arrange for the construction of a guar gum-processing factory that would produce a five year supply of guar for FTSI. FTSI terminated the supply agreement in mid-2012 before the factory was complete. With respect to the purchase order claim, FTSI had expressed interest in purchasing guar gum from Continental in transactions separate from the supply agreement. FTSI did not purchase the guar gum. Continental claimed that valid purchase orders had been formed and that FTSI wrongfully terminated the purchase orders when it decided not to purchase the guar gum. Continental sought damages of approximately $58.0 million related to the supply agreement claim and approximately $4.5 million related to the purchase order claim. FTSI filed counterclaims against Continental seeking damages in excess of $69.0 million representing the difference between the price it paid for guar gum in the spot market and the price it would have paid under the supply agreement. A jury trial for this case was held and, on November 3, 2015, the jury returned verdicts in favor of Continental for both claims. The jury awarded damages to Continental in the aggregate amount of $5.3 million, of which $2.1 million related to the supply agreement case and $3.2 million related to the purchase order case. In January 2016, we settled this lawsuit with Continental for a confidential amount and the financial effects of this matter have been included in our consolidated financial statements as of December 31, 2015.
We believe that costs associated with other legal matters will not have a material adverse effect on our consolidated financial statements.
NOTE 14 - NONRECURRING FAIR VALUE MEASUREMENTS
The following table represents the placement in the fair value hierarchy of assets that were measured at fair value on a nonrecurring basis. See Note 9 - “Impairments and Other Charges” for further discussion.
(1) Represents the value on the date of the fair value measurement.
(2) Equipment value based on pending contract price. Assets held for sale are classified as “Prepaid expenses and other current assets” on our Consolidated Balance Sheets.
(3) Valued using the income approach and the market approach valuation techniques.
(4) Valued using the income approach.
(5) Equipment valued using the cost approach, which is a valuation technique that estimates the amount that would be currently required to replace an asset’s service capacity.
(6) Property valued using the market approach based on the sales prices of comparable properties and/or estimates obtained from commercial brokers.
NOTE 15 - EARNINGS (LOSS) PER SHARE
The numerators and denominators of the basic and diluted earnings (loss) per share (“EPS”) computations for our common stock are calculated as follows:
(1) The weighted average shares outstanding has been adjusted to give effect to a 69.258777 : 1 reverse stock split that occurred in February 2018 in connection with the completion of an initial public offering of our common stock. See Note 17 - “Subsequent Events” for more information.
(2) Dilutive securities in our diluted EPS calculation do not include the effects of converting the convertible preferred stock because the effect would be antidilutive. The number of common stock equivalents attributable to convertible preferred stock was 13.0 million shares for all periods presented after giving effect to the reverse stock split discussed above.
(3) Dilutive securities in our diluted EPS calculation do not include RSUs granted under our 2014 LTIP. Vesting of these RSUs is dependent upon the satisfaction of both a service condition and a corporate liquidity event such as an initial public offering of our common stock. As of December 31, 2017, a corporate liquidity event had not occurred; therefore, the holders of these RSUs had no rights in our undistributed earnings. Therefore, they were excluded from the effect of dilutive securities. The number of common stock equivalents attributable to the RSUs were 117 thousand shares, 159 thousand shares and 238 thousand shares in 2017, 2016 and 2015, respectively, after giving effect to the reverse stock split discussed above.
NOTE 16 - SELECTED QUARTERLY DATA (UNAUDITED)
NOTE 17 - SUBSEQUENT EVENTS
In February 2018 the Company completed an initial public offering (“IPO”) of its common stock and completed a number of other transactions.
Initial Public Offering of Common Stock
We completed an initial public offering of 22.4 million shares of common stock at a price to the public of $18.00 per share, of which 18.1 million shares were sold by the Company and 4.3 million shares were sold by a subsidiary of Chesapeake. The shares began trading on The New York Stock Exchange on February 2, 2018, under the ticker symbol “FTSI.” The Company received net proceeds from the offering of approximately $303 million, and we intend to use the net proceeds from the offering for general corporate purposes, including debt repayments. The Company did not receive any proceeds from the offering of shares by the selling stockholder.
Reverse Stock Split
In connection with the IPO, we amended and restated our certificate of incorporation to effect a 69.258777:1 reverse stock split of our common stock. If the reverse stock split had occurred on December 31, 2017, our issued and outstanding common stock would have been 51.8 million shares.
Recapitalization of Convertible Preferred Stock
In connection with the IPO, a number of shares of our Preferred Stock converted into common stock at the rate of 155.944841 shares of common stock per each share of Preferred Stock. All remaining shares of Preferred Stock were cancelled. We refer to this conversion and the cancelation together as the recapitalization of the Preferred Stock. The conversion rate of the Preferred Stock and shares canceled were calculated so that following the recapitalization, stockholders that did not own Preferred Stock would own 7% of our common stock prior to the IPO. The recapitalization of all outstanding shares of our Preferred Stock resulted in approximately 39.4 million shares of common stock.
Debt Repayments
In February 2018, we repaid all $290.0 million remaining principal amount of 2020 Senior Notes using cash on hand and proceeds received from our IPO. We recognized a loss on debt extinguishment of $8.3 million.
In February 2018, we repaid $50.0 million of aggregate principal amount of Term Loan using cash on hand and proceeds received from our IPO. We recognized a loss on debt extinguishment of $0.5 million.
In January 2018, we repurchased $5.0 million of aggregate principal amount of 2022 Senior Notes in the qualified institutional market using cash on hand. We recognized an immaterial gain on debt extinguishment.
After these repayments, we had $785.0 million aggregate principal amount of long-term debt still outstanding.
Establishment of a New Revolving Credit Facility
On February 22, 2018, we entered into a $250 million revolving credit facility, with an initial maturity date of February 22, 2023, with a group of lenders with Wells Fargo, N.A., as administrative agent. The maturity date of the facility could be accelerated to January 16, 2021 or January 31, 2022, if we do not repay or refinance our Term Loan or 2022 Senior Notes, respectively, before these dates.
LIBOR borrowings under the credit facility bear interest at LIBOR plus a margin of 1.75% to 2.00% per annum, depending on facility utilization. Base rate loans are also available at our option. The credit facility includes a $50 million sub-limit for the issuance of letters of credit. The issuance of letters of credit reduces the amount available under the facility. We also pay a commitment fee on the unused amount of the facility of 0.25% to 0.375% per annum, depending on facility utilization.
The obligations under the credit facility are secured by substantially all of our accounts receivable, inventory, deposit accounts, intellectual property and the equity of some current and future wholly-owned domestic and foreign subsidiaries.
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. In an event of default or if the amount available under the 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.
The credit facility contains covenants that could, in certain circumstances, limit our ability to issue additional debt, repurchase or pay dividends on our common stock, sell substantially all of our assets, make certain investments, or enter into certain other transactions.
As of March 9, 2018, no borrowings were outstanding under the credit facility, and letters of credit totaling $11 million had been issued, resulting in $239 million of availability under the facility.