Item 1. Business
Corporate History
C&J Energy Services, Inc., a Delaware corporation (the “Successor” and together with its consolidated subsidiaries for periods subsequent to the Plan Effective Date (as defined below), “C&J” the “Company,” “we,” “us” or “our”) is a leading provider of well construction, intervention, completion, support and other complementary oilfield services and technologies. We provide our services to oil and gas exploration and production companies throughout the continental United States. We are a new well focused provider offering a diverse suite of services throughout the life cycle of the well, including hydraulic fracturing, cased-hole wireline and pumping, cementing, coiled tubing, rig services, fluids management and other completion and well support services. We are headquartered in Houston, Texas and operate across all active onshore basins in the continental United States.
We were founded in Texas in 1997 as a partnership and converted to a Delaware corporation (“Old C&J”) in connection with our initial public offering, which was completed in 2011 with a listing on the New York Stock Exchange (“NYSE”) under the symbol “CJES.” From 2011 through mid-2015, we significantly invested in a number of strategic initiatives to grow our business, including through service line diversification, vertical integration, technological advancement and geographic expansion, including internationally. In 2015, Old C&J combined with the completion and production services business (the “C&P Business”) of Nabors Industries Ltd. (“Nabors”) in a transformative transaction (the “Nabors Merger”) that significantly expanded the Company’s Completion Services and Well Construction and Intervention Services businesses and added the Well Support Services division to the Company’s service offering. Upon the closing of the Nabors Merger, Old C&J became a subsidiary of C&J Energy Services Ltd., a Bermuda corporation (the “Predecessor” and together with its consolidated subsidiaries for periods prior to the Plan Effective Date, the “Predecessor Companies”).
Due to a severe industry downturn, in July 2016, the Predecessor Companies voluntarily filed petitions for reorganization seeking relief under the provisions of Chapter 11 of the United States Bankruptcy Code in the United States Bankruptcy Court for the Southern District of Texas, Houston Division, with ancillary recognition proceedings filed in Canada and Bermuda (collectively, the “Chapter 11 Proceeding”).
The plan of reorganization (the “Restructuring Plan”) of the Predecessor Companies was confirmed in December 2016, and on January 6, 2017 (the “Plan Effective Date”), the Predecessor Companies substantially consummated the Restructuring Plan and emerged from the Chapter 11 Proceeding. Pursuant to the Restructuring Plan, effective on the Plan Effective Date, the Predecessor’s equity was canceled, the Predecessor transferred all of its assets and operations to the Successor and the Predecessor was subsequently dissolved. The Predecessor’s common stock was ultimately delisted from the NYSE. On April 12, 2017, the Successor completed an underwritten public offering of common stock and its common stock began trading again on the NYSE under the symbol “CJ.”
Upon emergence from the Chapter 11 Proceeding, we adopted fresh start accounting ("Fresh Start"). For more information regarding the Chapter 11 Proceeding and adoption of Fresh Start accounting, see Note 14 - Chapter 11 Proceeding and Emergence and Note 15 - Fresh Start Accounting in Part II, Item 8 “Financial Statements and Supplementary Data” of this Annual Report on Form 10-K (this “Annual Report”).
The Successor is the successor issuer to the Predecessor for purposes of and pursuant to Rule 12g-3 of the Exchange Act. Accordingly, references to “C&J,” the “Company,” “we,” “us” or “our” in this Annual Report are to the Successor, together with our consolidated subsidiaries when referring to periods following the Plan Effective Date, and to the Predecessor Companies when referring to periods prior to the Plan Effective Date.
Our principal executive offices are located at 3990 Rogerdale Road, Houston, Texas 77042 and our main telephone number at that address is (713) 325-6000. Our website is available at www.cjenergy.com. We file annual, quarterly and current reports and other documents with the U.S. Securities and Exchange Commission (“SEC”) under the Exchange Act. The SEC maintains an internet site at www.sec.gov that contains reports, proxy and information statements, reports and other information that we and other issuers file electronically with the SEC. We also make available free of charge through our website all reports filed with or furnished to the SEC pursuant to Section 13(a) or 15(d) of the Exchange Act, including our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, Proxy Statement on Schedule 14A and all amendments to those reports, as soon as reasonably practicable after such material is electronically filed with or furnished to the SEC. Information contained on or available through our website is not a part of or incorporated into this Annual Report or any other report that we may file with or furnish to the SEC.
Business Overview
From late 2011 through mid-2016, we executed an aggressive growth strategy that diversified the Company’s service offerings and geographic reach (including in such locations as the Middle East, the Americas, and Europe). With the change in our executive team and subsequent Chapter 11 Proceeding in 2016, we refocused our strategy and plans. Beginning in 2016 and into 2018, we divested our non-core businesses, including specialty chemicals, equipment manufacturing, directional drilling and artificial lift. Additionally, we shut down our emergent Middle East operations in 2016 (completing the liquidation in 2018), and sold our Canadian rig business in November 2017, in furtherance of our goal of becoming the leading oilfield services provider across our service offering in onshore basins in the continental United States.
In November 2017, we acquired O-Tex Holdings, Inc., a Texas corporation ("O-Tex"), for approximately $271.9 million, making us one of the largest oilfield cementers in the continental United States. In connection with this transaction, we also acquired the remaining 49.0% non-controlling interest in a partially owned O-Tex subsidiary for $1.25 million, which strengthened the data controls instrument business of our research and technology efforts (collectively, the "O-Tex Transaction"). O-Tex specialized in both primary and secondary downhole specialty cementing services in most major U.S. shale plays. The O-Tex Transaction strengthened our position as a leading oilfield services provider with a best-in-class well construction, intervention and completions platform.
In 2018, we focused on the continuous improvement of our organization, including advancing several ongoing initiatives purposed to strengthen our organization, optimize our business processes, ensure the quality of our operations, and gain greater efficiency over time. We also took a deliberate approach to increasing our core capabilities, adding capacity, growing our core service lines, and fully integrating the O-Tex asset base.
Our Reportable Segments and Strategy
During the first quarter of 2018, we revised our reportable segments. This revision eliminated the Other Services segment, which consisted of those smaller, non-core business lines that have since been divested, including our specialty chemical business, equipment manufacturing and repair business, and coiled tubing operations in the Middle East. In line with the discontinuance of these business lines, subsequent to the year ended December 31, 2016, financial information for the Other Services reportable segment is only presented for the corresponding prior year period. As a result of the revised reportable segment structure, we have restated the corresponding items of the segment information for all periods presented. As of December 31, 2018, our reportable segments were:
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Completion Services, which consists of the following business lines: (1) fracturing services; (2) cased-hole wireline and pumping services; and (3) completion support services, which includes our research and technology (“R&T”) department.
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Well Construction and Intervention Services ("WC&I"), which consists of the following business lines: (1) cementing services and (2) coiled tubing services.
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Well Support Services, which consists of the following business lines: (1) rig services; (2) fluids management services; and (3) specialty well site services.
During the first quarter of 2018, we decided to exit our directional drilling business and artificial lift business. We are in the process of divesting the assets and inventory associated with our directional drilling operations. We completed the sale of substantially all of the assets and inventory associated with the artificial lift business on July 2, 2018.
Each reportable segment is described in more detail below. Our results of operations in our core service lines are driven primarily by five interrelated, fluctuating variables: (1) the drilling, completion and production activities of our customers, which is primarily driven by oil and natural gas prices and directly affects the demand for our services; (2) the price we are able to charge for our services and equipment, which is primarily driven by the level of demand for our services and the supply of equipment capacity in the market; (3) the cost of materials, supplies and labor involved in providing our services, and our ability to pass those costs on to our customers; and (4) our activity, or “utilization” levels; and (5) the quality, safety and efficiency of our service execution.
Our management team monitors asset utilization, among other factors, for purposes of assessing our overall activity levels and customer demand. For our Completion Services segment, we measure our asset utilization levels primarily by the total number of days that our asset base works on a monthly basis, based on the available working days per month, which
excludes scheduled maintenance days. We generally consider an asset to be working such days that it is at or in transit to a job location, regardless of the number of hours worked or whether it generated any revenue during such time. In our Well Construction and Intervention Services segment, we measure our asset utilization levels for our cementing business primarily by the total number of days that our asset base works on a monthly basis, based on the available working days per month. In our coiled tubing business, we measure certain asset utilization levels by the hour to better understand measures between daylight and 24-hour operations. Both the financial and operating performance of our coiled tubing and cement units can vary in revenue and profitability from job to job depending on the type of service to be performed and the equipment, personnel and consumables required for the job, as well as competitive factors and market conditions in the region in which the services are performed. In our Well Support Services segment, we measure asset utilization levels primarily by the number of hours our assets work on a monthly basis, based on the available working days per month.
Our operating strategy is focused on maintaining high asset utilization levels to maximize revenue generation while controlling costs to gain a competitive advantage and drive returns. We believe that the safety, quality and efficiency of our service execution and our alignment with customers who recognize the value that we provide are central to our efforts to support utilization and grow our business. Given the volatile and cyclical nature of activity drivers in the U.S. onshore oilfield services industry, coupled with the varying prices we are able to charge for our services and the cost of providing those services, among other factors, operating margins can fluctuate widely depending on supply and demand at a given point in the cycle. For additional information about factors impacting our business and results of operations, please see “Industry Trends and Outlook” in Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in this Annual Report.
Completion Services
The core services provided through our Completion Services segment are fracturing and cased-hole wireline and pumping services. We utilize our in-house manufacturing capabilities, including our R&T department and data control instruments business, to offer a technologically advanced and efficiency focused range of completion techniques. The majority of revenue for this segment is generated by our fracturing business.
Fracturing. Our fleet is capable of handling the most technically demanding well completions in conventional and unconventional high-pressure formations. We leverage our R&T capabilities to provide customers with engineered frac designs, refracturing and other reservoir stimulation services that help regain production and increase well recovery. We also can provide our services using smaller frac fleets in response to customer demand for vertical fracs and restimulation services.
Cased-hole Wireline and Pumping. Through our cased-hole wireline and pumping services business, we are one of the leading providers of perforating, pumpdown, pipe recovery, pressure pumping, and wellsite make-up and pressure testing services. We are highly experienced in safely servicing deep, high-pressure, high-temperature wells in some of the most active onshore basins in the United States and provide premium perforating services for both wireline and tubing-conveyed applications. Our in-house manufacturing capabilities through our R&T department allow us to manage costs and lead times with regard to hardware and perforating guns, switches and accessories, providing us with a competitive advantage and enabling higher returns.
Well Construction and Intervention Services
Cementing. Following the closing of the O-Tex Transaction, we are one of the largest providers of specialty cementing services in the United States. Our operations are supported by multiple full-service laboratory facilities with advanced capabilities.
Coiled Tubing. We offer a complete range of coiled tubing services to help customers accomplish a wide variety of goals in their horizontal completion, workover and well maintenance projects. The majority of our coiled tubing fleet consists of large diameter coil, meaning two inches or larger in diameter, which allows us to service wells with longer lateral lengths. Our coiled tubing services allow customers to complete projects quickly and safely across a wide spectrum of pressures, without having to shut in their wells.
Well Support Services
Our Well Support Services segment focuses on post-completion activities at the well site, and includes rig services, such as workover, fluids management, and other specialty well site services. Although we previously provided artificial lift applications through this segment, we completed the sale of substantially all of the assets and inventory associated with this
business on July 2, 2018. The majority of revenue for this segment is generated by our rig services business, and we consider our rig services and fluids management businesses to be our core service lines within this reportable segment.
Rig Services. As part of our services that help prolong the productive life of an oil or gas well, we operate one of the largest fleets in the United States. These rigs are involved in the routine repair and maintenance of oil and gas wells, re-drilling operations and plug and abandonment operations. Workover services can include deepening or extending wellbores into new formations by drilling horizontal or lateral wellbores, sealing off depleted production zones and accessing previously bypassed production zones, converting former production wells into injection wells for enhanced recovery operations and conducting major subsurface repairs due to equipment failures. Workover services may last from a few days to several weeks, depending on the complexity of the workover. Maintenance services provided with our rig fleet are generally required throughout the life cycle of an oil or gas well. Examples of these maintenance services include routine mechanical repairs to the pumps, tubing and other equipment, removing debris and formation material from wellbores, and pulling rods and other downhole equipment from wellbores to identify and resolve production problems. Maintenance services are generally less complicated than completion and workover related services and require less time to perform. Our rig fleet is also used in the process of permanently shutting-in oil or gas wells that are at the end of their productive lives. These plugging and abandonment services generally require auxiliary equipment in addition to a well servicing rig. The demand for plugging and abandonment services is not significantly impacted by the demand for oil and gas because well operators are required by state regulations to plug wells that are no longer productive.
Fluids Management. We provide a full range of fluid services, including the storage, transportation and disposal of various fluids used in the drilling, completion and workover of oil and gas wells. Our fleet of trucks and trailers and portable tanks enable us to rapidly deploy our equipment across a broad geographic area. Included in our fleet of fluid trucks and trailers are specialized trucks and trailers that are optimized to transport condensate. We also own private salt water disposal wells. Demand and pricing for our fluids management services generally correspond to demand for our rig services.
Other Information About Our Business
Seasonality
Our operations are subject to seasonal factors and our overall financial results reflect the seasonal variations that impact activity in our core business lines. Specifically, we typically have experienced a pause by our customers around the holiday season in the fourth quarter, which may be compounded as our customers exhaust their annual capital spending budgets towards year end. Additionally, our operations are directly affected by weather conditions. During the winter months our customers may delay operations or we may not be able to operate or move our equipment between locations during periods of heavy snow, ice or rain, and during the spring some areas impose transportation restrictions due to the muddy conditions caused by the spring thaws. During the summer months, our operations may be impacted by tropical weather systems.
Sales and Marketing
Sales of our core business lines are primarily generated by the efforts of our sales force, working closely with our operations teams.
Sales and marketing activities are typically performed through our local operations in each geographic region, as well as through our corporate sales teams in Houston. For our other core business lines, we believe our local field sales personnel have a strong understanding of region-specific issues and customer operating procedures and, therefore, can effectively target marketing activities. We also have multiple corporate sales representatives that supplement our field sales efforts and focus on large accounts and selling technical services. Our sales representatives collaborate with our legal team to identify customer contracting needs in advance of potential operations, which we believe helps streamline our customer onboarding process. Our sales representatives work closely with our local managers and field sales personnel to target compelling market opportunities. Our ability to deliver integrated services through the life of the well and strong track record provides cross-selling and bundling opportunities with existing customers. We facilitate teamwork among our sales representatives by basing a portion of their compensation on aggregate company sales targets rather than individual sales targets. We believe this emphasis on teamwork enables us to better serve our existing customers and may also allow us to further expand our customer base, including through cross-selling and bundling opportunities.
We offer relatively short-term services that generally are cancelable at any time, and as such have no backlogs.
Customers
We serve a diverse group of independent and major national oil and gas companies that are active in our core areas of operations across the continental United States. We seek customers who value our technology, safety priorities and efficiency capabilities. We monitor the financial condition of our customers, their capital expenditure plans and other indications of their drilling, completion and production services activity. In particular, we seek to identify distressed customers and apply what we believe to be appropriate business and legal measures to protect us from any defaults or failures to pay.
Our top ten customers accounted for approximately 44.2%, 40.7% and 46.0% of our consolidated revenue for the years ended December 31, 2018, 2017 and 2016, respectively. There were no individual customers that accounted for more than 10.0% of our consolidated revenues during the years ended December 31, 2018, 2017 and 2016. If we were to lose any material customer or group of customers that were material in the aggregate, we may not be able to redeploy our equipment at similar utilization or pricing levels and such loss could have an adverse effect on our business until the equipment is redeployed at similar utilization or pricing levels.
Competition
We operate in highly competitive areas of the oilfield services industry with significant potential for excess capacity. Equipment can be moved from one region to another in response to changes in levels of activity and market conditions, which may result in an oversupply of assets relative to activity in any particular area. Utilization and pricing for our services have from time to time been negatively affected by increases in supply relative to demand in our operating areas and geographic markets.
The demand for our services depends primarily on the level of spending by oil and gas companies for drilling, completion and production activities, which is affected by short-term and long-term trends in oil and natural gas prices and numerous other factors over which we have no control. Severe declines and sustained weakness and volatility in commodity prices may negatively impact the level of drilling, completion and production activity and capital expenditures by our customers, adversely affected the demand for our services. This, in turn, may negatively impact our ability to maintain adequate utilization of our asset base and to negotiate pricing at levels generating sufficient margins.
Our revenues and earnings are directly affected by changes in the utilization of our assets and pricing for our services, which fluctuate in direct response to changes in the level of drilling, completion and production activity by our customers. Pressure on pricing for our services, including due to competition and industry and/or economic conditions, may impact, among other things, our ability to maintain utilization and profitability. During periods of declining pricing for our services, we may not be able to reduce our costs accordingly, which could further adversely affect our results. Furthermore, even when we are able to increase our prices, we may not be able to do so at a rate that is sufficient to offset any rising costs. 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 our costs increase, could have a material adverse effect on our business, financial position and results of operations.
Our competitors include many large and small energy service companies, including some of the largest integrated oilfield services companies that possess substantially greater financial and other resources than we do. Our larger competitors may be able to compete more effectively than we can, including by reducing prices to levels that we cannot sustain for our services. Our major competitors for both our Completion Services and Well Construction and Intervention Services segments include Halliburton, Schlumberger, BJ Services, Keane Group, RPC, Inc., FTS International, Inc., ProPetro Holding Corp., Basic Energy Services, Superior Energy Services, CalFrac Well Services, as well as a significant number of regional, predominantly private businesses. Our major competitors for our Well Support Services include Key Energy Services, Basic Energy Services, Superior Energy Services, Precision Drilling, Forbes Energy Services, Pioneer Energy Services and Ranger Energy Services, as well as a significant number of predominantly private, regional businesses.
Generally, we believe that the principal competitive factors in the markets that we serve are price, technical expertise, equipment capacity and quality, work force capability, safety record, reputation and experience. Although we believe our customers consider all of these factors, price is often the primary factor in determining which service provider is awarded work, particularly during times of weak or volatile commodity prices. Additionally, projects for certain of our core services are often awarded on a bid basis, which tends to further increase competition based primarily on price. During a downturn, our utilization and pricing levels may also be negatively impacted by predatory pricing from certain large competitors, who elect to operate at negative margins in attempt to gain or retain market share.
During healthier market conditions, we believe many of our customers choose to work with us based on our life-of-well capabilities, geographic footprint and scale, reputation for safety, the quality of our crews, equipment and services, and our value-added technology, although we must always be competitive in our pricing. We seek to differentiate ourselves from our major competitors by our operating philosophy, which is focused on delivering the highest quality customer service and equipment, safely and with superior execution and operating efficiency. As part of this strategy, we seek customers who are aligned with our strengths and want dedicated services, and we target high volume, high efficiency customers with service intensive, 24-hour work, which is where we believe we can differentiate our services from our competitors.
See Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Industry Trends and Outlook” for additional discussion of the market challenges within our industry.
Research & Technology, Intellectual Property
Over the last several years we have significantly invested in technological advancement, including the development of a state-of-the-art research and technology center staffed by a team of highly skilled engineers. Our efforts to date have been focused on developing innovative, fit-for-purpose solutions designed to enhance our service offerings, increase efficiencies, provide cost savings to our operations and add value for our customers. Our R&T initiatives generate monthly cost savings for our integrated completion services operations, which is central to our overall strategy of proactively managing our costs to maximize returns. Several of these investments provide value added products and services that, in addition to producing revenue, are creating increasing demand from key customers. In our day-to-day operations, we utilize equipment and products manufactured by our vertically integrated businesses which are managed through our R&T department, and we also sell such equipment and products to third-party customers in the global energy services industry. We believe that our focus on R&T provides a significant strategic benefit through the ability to develop and implement new technologies and quickly respond to changes in customer requirements and industry demand.
We seek patent and trademark protection for our technology when we deem it prudent, and we aggressively pursue protection of these rights. We believe our patents and trademarks are adequate for the conduct of our business and that no single patent or trademark is critical to our business. We also rely, to a significant extent, on the technical expertise and know-how of our personnel to maintain our competitive position.
See Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for additional detail as to our investment in technological advancement.
Suppliers
We purchase raw materials (such as proppant, guar, acid, chemicals, completion fluids, cement and coiled tubing strings) and finished products (such as fluid ends, valves, power ends and pump consumables) used in our Completion Services segment and our Well Construction and Intervention Services segment and certain raw materials and finished products used in our Well Support Services segment from various third-party suppliers.
We are not materially dependent on any single supply source for the materials or products that are critical to our operations, and we believe that we would be able to make satisfactory alternative arrangements in the event of any interruption in the supply or recall of these materials and/or products by one of our suppliers. However, if alternative sources of supply are unavailable and we are unable to purchase the necessary materials and/or products needed for our business in a timely manner and in the quantities required, we may be delayed in providing our services, which could have a material adverse effect on our business, financial condition, results of operations and cash flows. For example, in the past, our industry has faced sporadic guar and proppant shortages and trucking shortages associated with hydraulic fracturing operations requiring work stoppages, which adversely impacted the operating results of several of our competitors. Additionally, increasing costs of certain raw materials, such as guar, may negatively impact demand for our services or the profitability of our business operations.
During the year ended December 31, 2018, one supplier from our Well Completions Services segment, Covia Corporation, supplied 7.2%, of our total Company's materials and/or products; but no single third-party supplier from our Well Construction and Intervention Services segment and Well Support Services segment supplied 5.0% or more of the Company's materials and/or products. In conjunction with the sale of our manufacturing business line, we also entered into a preferred supply agreement with a third-party to supply us with components and finished goods to repair and refurbish certain of our hydraulic fracturing equipment.
Quality, Health, Safety and Environmental (“QHSE”) Program
Our business involves the operation of extremely heavy and powerful equipment and the use of explosive and radioactive materials, among other hazards. If not well managed, these operations have the potential to result in serious injuries to our employees and/or third-parties and substantial damage to property or the environment. We commit significant resources towards employee safety and have a robust new hire program. We also have comprehensive QHSE-focused training programs designed to minimize accidents in the workplace and improve the safety, quality and efficiency of our operations. We believe that our QHSE policies, standards and procedures, which are reviewed internally for compliance with industry changes, provide a reliable framework to ensure our operations minimize the hazards inherent in our work and meet regulatory requirements and customer demands. Further, we are in the process of implementing a quality management system that will create standardization of processes throughout all facets of our business, support our risk mitigation strategy and help ensure compliance with our procedures and processes.
Our record and reputation for safety are important to all aspects of our business. In the oilfield services industry, a critical competitive factor in establishing and maintaining long-term customer relationships is having an experienced, skilled and well-trained work force. In recent years, many of our larger customers have placed an added emphasis on the safety records and quality management systems of their contractors. We strive to meet or exceed the safety and quality management requirements of our customers, and we believe our continued focus on safety will gain even further importance to our customers as the market continues to improve. Our reputation and proven safety record have allowed us to earn work certifications from several industry leaders that we believe have some of the most demanding safety requirements, including ConocoPhillips, ExxonMobil, Chevron and Royal Dutch Shell.
Risk Management and Insurance
Our operations are subject to hazards inherent in the oil and gas industry, including blowouts, explosions, cratering, fires, oil spills, surface and underground pollution and contamination, hazardous material spills, loss of well control, damage to or loss of the wellbore, formation or underground reservoir, damage or loss from the use of explosives and radioactive materials, and damage or loss from inclement weather or natural disasters. Any of these hazards could result in personal injury or death, damage to or destruction of equipment and facilities, loss of oil and natural gas production, suspension of operations or loss of license to conduct business, damage to or destruction of the environment and natural resources and damage to or destruction of the property of others. Additionally, our business involves, and so is subject to hazards associated with, the transportation of heavy equipment and materials, as well as heavily regulated explosive and radioactive materials. Regularly having a significant number of both commercial and non-commercial motor vehicles on the road creates a high risk of vehicle accidents that may result in personal injury or death, damage to or destruction of equipment and the property of others and hazardous material spills. The occurrence of a serious accident involving our employees, equipment and/or services, could result in C&J being named as a defendant in lawsuits asserting large claims for damages. C&J could also be liable to indemnify certain third-parties, specifically including its customers, for large claims for damages in situations where our employees, equipment and/or services were involved.
Despite our efforts to maintain high safety and security standards, we from time to time have suffered accidents, outages, breaches, and other incidents, and it is likely that we will experience the same in the future. In addition to the property and personal losses from these events, the frequency and severity of these incidents affect our operating costs and insurability, as well as our relationship with customers, employees and regulatory agencies. Any significant increase in the frequency or severity of these incidents, or the general level of compensatory payments, could adversely affect the cost of, or our ability to obtain, workers’ compensation and other forms of insurance, and could have other material adverse effects on our financial condition and results of operations. In addition, our business relies heavily on sophisticated information technology systems and infrastructure, the failure of which may cause disruptions to our operations. Any such failure, whether resulting from outages, employee error, cyber-attacks, or other similar events, may have an adverse impact on our financial condition.
We carry a variety of insurance coverages for our operations including coverage for workers’ compensation and employers liability, automobile liability, general liability, which also includes sudden and accidental pollution insurance, environmental liability, and property damage relating to catastrophic events, together with excess loss liability coverage. These insurance policies carry self-insured retention limits or deductibles on a per occurrence basis at levels we believe to be customary and reasonable. We have deductibles per occurrence for: workers’ compensation and employers liability claims of $1,000,000; automobile liability claims of $1,000,000; general liability claims, including sudden and accidental pollution claims, of $250,000, plus an additional annual aggregate deductible of $250,000; environmental liability claims of $500,000; and property damage for catastrophic events of $50,000. The excess loss liability coverage is subject to a self-insured retention of $5,000,000 for each occurrence and in the aggregate. We also carry coverage applicable to a number of cyber liabilities,
including cyber extortion, security failures, and network interruptions. These cyber liability coverages are subject to a self-insured retention of $100,000 for each occurrence.
With respect to the C&P Business that we acquired from Nabors in the Nabors Merger, and as a result of the settlement agreement negotiated with Nabors in connection the Chapter 11 Proceeding, we assumed, among other liabilities, all liabilities of the C&P Business to the extent arising out of or resulting from the operation of the C&P Business at any time before, at or after the closing of the Nabors Merger, including liability for death, personal injury and property damage resulting from or caused by the assets, products and services of the C&P Business, other than those liabilities specifically identified in the settlement agreement, as incorporated into the Restructuring Plan, for which Nabors maintains a continuing indemnification obligation. Please see “U.S. Department of Justice Criminal Investigation into Pre-Nabors Merger Incident” in Part I, Item 3 “Legal Proceedings” for additional information about the certain legal proceedings related to the C&P Business.
As discussed below, our Master Service Agreements (“MSAs”) with our customers generally provide, among other things, that our customers generally assume (without regard to fault) liability for underground pollution and pollution emanating from the wellbore as a result of an explosion, fire or blowout. We retain the risk for any liabilities which we cause, and which are not otherwise indemnified by our customers. This includes liability to indemnify our customer for certain liabilities. Our insurance coverage may be inadequate to cover our liabilities. In addition, we may not be able to maintain adequate insurance in the future at rates we consider reasonable and commercially justifiable or on terms as favorable as our current arrangements.
We strive to enter into MSAs with each of our customers before providing any services. Our sales and operations teams work closely with our legal team to identify and prioritize MSAs for negotiation, which we believe increases the efficiency of our risk management efforts. These MSAs delineate our and our customers’ respective warranty and indemnification obligations with respect to the services we provide. With respect to warranty issues, our MSAs typically provide that our obligations are limited to replacing any defective good or services, or in the alternative, providing the customer with a refund. Our MSAs typically provide for knock-for-knock indemnification for all bodily injuries and property losses arising from our work, which means that we and our customers assume (without regard to fault) liability for damages to our respective personnel and property. For catastrophic losses, our MSAs generally include industry-standard carve-outs from the knock-for-knock indemnities, pursuant to which our customers (typically the exploration and production companies) assume (without regard to fault) liability for (i) damage to the well bore, including the cost to re-drill; (ii) damage to the formation, underground strata and the reservoir; (iii) damages or claims arising from loss of control of a well or a blowout; and (iv) allegations of subsurface trespass. Additionally, our MSAs often provide carve-outs to the “without regard to fault” concept that would permit, for example, us to be held responsible for events of catastrophic loss to the extent they arise as a result of our gross negligence or willful misconduct. Our MSAs typically provide for industry-standard pollution indemnities, pursuant to which we assume liability for surface pollution associated with our equipment and originating above the surface (without regard to fault), and our customer assumes (without regard to fault) liability arising from all other pollution, including, without limitation, underground pollution and pollution emanating from the wellbore as a result of an explosion, fire or blowout. In certain circumstances, we agree to exceptions from our MSAs’ catastrophic loss and pollution indemnities to the extent incidents arise from our gross negligence or willful misconduct.
The description of insurance policies set forth above is a summary of certain material terms of our insurance policies currently in effect and may change in the future as a result of market and/or other conditions. Similarly, the summary of MSAs set forth above is a summary of the material terms of the typical MSA that we have in place, but does not reflect every MSA that is in effect or that we may enter into in the future, some of which may contain indemnity structures and risk allocations between our customers and us that are different and less favorable than those described here.
Employees
As of February 22, 2019, we have 6,399 employees. The delivery of our core completion services requires personnel with specialized skills and experience who can perform physically demanding work. Due to the commodity price volatility often experienced in the energy services industry and the demanding nature of the work, workers often choose to pursue employment in fields that offer a less strenuous work environment. During periods of high demand for oil field services, there can be extreme competition amongst employers to attract and retain skilled workers, which often results in a shortage of qualified employees and attrition due to wage escalation by competitors. Additionally, in our Well Support Services segment we continue to experience labor shortages for qualified drivers with a commercial driver's license and workover rig operators for our rig services business.
Our employees are not represented by any labor unions or covered by collective bargaining agreements. We consider our relations with our employees to be generally good.
Government Regulations and Environmental, Health and Safety Matters
We are significantly affected by stringent and complex federal, state and local laws and regulations, including those governing worker health and safety, motor carrier operations, the transportation of explosives, the use, management and disposal of certain radioactive materials, the handling of hazardous materials and the emission or discharge of substances into the environment or otherwise relating to environmental protection. Regulations concerning equipment certification create an ongoing need for regular maintenance, which is incorporated into our daily operating procedures. The regulatory burden on the industry increases the cost of doing business and consequently affects profitability. Any failure by us to comply with such local, state and federal laws and regulations may result in governmental authorities taking actions against our business that could adversely impact our operations and financial condition, including the following:
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issuance of administrative, civil and criminal penalties;
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modification, denial or revocation of permits or other authorizations;
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imposition of limitations on our operations through injunctions or other governmental actions; and
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performance of site investigatory, remedial or other corrective actions.
Worker Health and Safety
We are subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”), and comparable state statutes that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard requires that information be maintained about hazardous materials used or produced in operations and that this information be provided to employees, state and local government authorities and the public. OSHA has implemented stricter standards for worker exposure to silica, which would apply to use of sand as a proppant for hydraulic fracturing. These new standards require the oil and gas industry to implement engineering controls and work practices to limit exposures below the new limits by June 23, 2021.
Motor Carrier Operations
Among the services we provide, we operate as a motor carrier and therefore are subject to regulation by the United States Department of Transportation (“DOT”) and various state agencies. These regulatory authorities exercise broad powers, governing activities such as the authorization to engage in motor carrier operations; regulatory safety; hazardous materials labeling, placarding and marking; financial reporting; and certain mergers, consolidations and acquisitions. There are additional regulations specifically relating to the trucking industry, including testing and specification of equipment and product handling requirements. The trucking industry is subject to possible regulatory and legislative changes that may affect the economics of the industry by requiring changes in operating practices or by changing the demand for common or contract carrier services or the cost of providing truckload services. Some of these possible changes include increasingly stringent environmental regulations, changes in the hours of service regulations which govern the amount of time a driver may drive in any specific period and requiring onboard black box recorder devices or limits on vehicle weight and size. For example, in December 2016, the DOT finalized minimum training standards for new drivers seeking a commercial driver’s license. Certain motor vehicle operators are required to register with the DOT. This registration requires an acceptable operating record. The DOT periodically conducts compliance reviews and may revoke registration privileges based on certain safety performance criteria, and a revocation could result in a suspension of operations. Since 2010, the DOT has pursued its Compliance, Safety, Accountability (“CSA”) program, in an effort to improve commercial truck and bus safety. A component of CSA is the Safety Measurement System (“SMS”), which analyzes all safety violations recorded by federal and state law enforcement personnel to determine a carrier’s safety performance. The SMS is intended to allow DOT to identify carriers with safety issues and intervene to address those problems.
Interstate motor carrier operations are subject to safety requirements prescribed by DOT. To a large degree, intrastate motor carrier operations are subject to safety regulations that mirror federal regulations. Such matters as weight and dimension of equipment are also subject to federal and state regulations. DOT regulations also mandate drug testing of drivers. From time to time, various legislative proposals are introduced, including proposals to increase federal, state or local taxes, including taxes on motor fuels, which may increase our costs or adversely impact the recruitment of drivers. We cannot predict whether, or in what form, any increase in such taxes applicable to us will be enacted.
Radioactive Materials
In addition, some of our operations utilize equipment that contains sealed, low-grade radioactive sources. Our activities involving the use of radioactive materials are regulated by the United States Nuclear Regulatory Commission (“NRC”) and state regulatory agencies under agreement with the NRC. Standards implemented by these regulatory agencies require us to obtain licenses or other approvals for the use of such radioactive materials. We believe that we have obtained these licenses and approvals as necessary and applicable. Numerous governmental agencies issue regulations to implement and enforce these laws, for which compliance is often costly and difficult. The violation of these laws and regulations may result in the denial or revocation of permits, issuance of corrective action orders, injunctions prohibiting some or all of our operations, assessment of administrative and civil penalties, and even criminal prosecution. In addition, releases of radioactive material could result in substantial remediation costs and potentially expose us to third-party property damage or personal injury claims.
Hazardous Substances
We generate wastes, including hazardous wastes, which are subject to the federal Resource Conservation and Recovery Act (“RCRA”), and comparable state statutes. The U.S. Environmental Protection Agency (“EPA”), the NRC, and state agencies have limited the approved methods of disposal for some types of hazardous and nonhazardous wastes. RCRA currently excludes drilling fluids, produced waters and certain other wastes associated with the exploration, development or production of oil and natural gas from regulation as “hazardous waste.” Disposal of such non-hazardous oil and natural gas exploration, development and production wastes is usually regulated by state law. Other wastes handled at exploration and production sites or generated in the course of providing well services may not fall within this exclusion. Moreover, stricter standards for waste handling and disposal may be imposed on the oil and natural gas industry in the future. For example, in December 2016, the EPA and environmental groups entered into a consent decree to address the EPA’s alleged failure to timely assess its RCRA Subtitle D criteria regulations exempting certain exploration and production related oil and gas wastes from regulation as hazardous wastes under RCRA. The consent decree requires the EPA to propose a rulemaking no later than March 15, 2019 for revision of certain Subtitle D criteria regulations pertaining to oil and gas wastes or to sign a determination that revision of the regulations is not necessary. If the EPA proposes new rulemaking, the 2016 consent decree requires the EPA to take final action on such rules no later than July 15, 2021. Removal of RCRA’s exemption for exploration and production wastes has the potential to significantly increase waste disposal costs, which in turn will result in increased operating costs and could adversely impact our business and results of operations. The impact of future revisions to environmental laws and regulations cannot be predicted.
Naturally Occurring Radioactive Materials (“NORM”) may contaminate extraction and processing equipment used in the oil and natural gas industry. The waste resulting from such contamination is regulated by federal and state laws. Standards have been developed for: worker protection; treatment, storage, and disposal of NORM and NORM waste; management of NORM-contaminated waste piles, containers and tanks; and limitations on the relinquishment of NORM contaminated land for unrestricted use under RCRA and state laws. It is possible that we may incur costs or liabilities associated with elevated levels of NORM.
The Federal Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA” or the “Superfund” law), and comparable state statutes impose joint and several liability, without regard to fault or legality of the original conduct, on classes of persons who are considered to have been responsible for the release of a hazardous substance into the environment. Such classes of persons include the current and past owners or operators of sites where a hazardous substance was released, and companies that disposed or arranged for disposal of hazardous substances at off-site locations such as landfills. Under CERCLA, these persons may be subject to strict, joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources, and it is not uncommon for neighboring landowners and other third-parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. We currently own, lease, or operate numerous properties and facilities that for many years have been used for industrial activities, including oil and natural gas related operations. Hazardous substances, wastes, or hydrocarbons may have been released on or under the properties owned or leased by us, or on or under other locations where such substances have been taken for recycling or disposal. In addition, some of these properties have been operated by third-parties or by previous owners whose treatment and disposal or release of hazardous substances, wastes, or hydrocarbons, was not under our control. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to remove previously disposed substances and wastes and remediate contaminated property (including groundwater contamination), including instances where the prior owner or operator caused the contamination, or perform remedial plugging of disposal wells or waste pit closure operations to prevent future contamination. These laws and regulations may also expose us to liability for our acts that were in compliance with applicable laws at the time the acts were performed.
Water Discharges
The Federal Water Pollution Control Act (the “Clean Water Act”), and comparable state statutes impose restrictions and strict controls regarding the discharge of pollutants into state waters or waters of the United States. The discharge of pollutants into jurisdictional waters is prohibited unless the discharge is permitted by the EPA or applicable state agencies. The Clean Water Act also prohibits the discharge of dredge and fill material into regulated waters, including jurisdictional wetlands, unless authorized by an appropriately issued permit. In September 2015, the EPA and U.S. Army Corps of Engineers (the “Corps”) issued a new rule defining the scope of the EPA’s and the Corps’ jurisdiction over wetlands and other waters. On December 11, 2018, EPA and the Corps issued a proposed new rule that would differently revise the definition of waters of the United States and essentially replace the 2015 rule. According to the agencies, the proposed new rule is intended to increase CWA program predictability and consistency by increasing clarity as to the scope of ‘waters of the United States’ federally regulated under the Act. If finalized, this new definition of waters of the United States will likely be challenged and sought to be enjoined in federal court. Until that time, regulations are being implemented as they were prior to August 2015. A public hearing on this proposed rule was scheduled for January 23, 2019, but this hearing was postponed due to the shutdown of the federal government in early 2019. The process for obtaining permits has the potential to delay the development of natural gas and oil projects. Also, spill prevention, control and countermeasure regulations under federal law require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak.
In addition, the Clean Water Act and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. Moreover, the Oil Pollution Act of 1990 (“OPA”) imposes a variety of requirements on responsible parties related to the prevention of oil spills and liability for damages, including natural resource damages, resulting from such spills in waters of the United States. A responsible party includes the owner or operator of an onshore facility. The Clean Water Act and analogous state laws provide for administrative, civil and criminal penalties for unauthorized discharges and, together with the OPA, impose rigorous requirements for spill prevention and response planning, as well as substantial potential liability for the costs of removal, remediation, and damages in connection with any unauthorized discharges.
The Safe Water Drinking Act (“SDWA”) regulates the underground injection of substances through the Underground Injection Control (“UIC”) program. Hydraulic fracturing generally is exempt from regulation under the UIC program, and the hydraulic fracturing process is typically regulated by state oil and gas commissions. However, the EPA has asserted that hydraulic fracturing with fluids containing diesel fuel is subject to regulation under the UIC program. In addition, in response to recent seismic events near underground injection wells used for the disposal of oil and gas-related wastewater, federal and some state agencies have begun investigating whether such wells have caused increased seismic activity, and some states have imposed volumetric injection limits, shut down or imposed moratorium on the use of such injection wells. If new regulatory initiatives are implemented that restrict or prohibit the use of underground injection wells in areas where we rely upon the use of such wells in our operations, our costs to operate may significantly increase and our ability to perform services may be delayed or limited, which could have an adverse effect on our results of operations and financial position.
Air Emissions
Some of our operations also result in emissions of regulated air pollutants. The federal Clean Air Act (“CAA”) and analogous state laws require permits for certain facilities that have the potential to emit substances into the atmosphere that could adversely affect environmental quality. These laws and their implementing regulations also impose generally applicable limitations on air emissions and require adherence to maintenance, work practice, reporting and record keeping, and other requirements. Failure to obtain a permit or to comply with permit or other regulatory requirements could result in the imposition of substantial administrative, civil and even criminal penalties. In addition, we or our customers could be required to shut down or retrofit existing equipment, leading to additional expenses and operational delays.
Many of these regulatory requirements, including New Source Performance Standards and Maximum Achievable Control Technology standards have been made more stringent over time as a result of stricter ambient air quality standards and other air quality protection goals adopted by the EPA. For example, in October 2015, the EPA lowered the National Ambient Air Quality Standard, (“NAAQS”) for ozone from 75 to 70 parts per billion for both the 8-hour primary and secondary standards. Subsequently, in November 2017, the EPA published a list of areas that are in compliance with the new ozone standards and separately in December 2017 issued responses to state recommendation for designating nonattainment areas. Remaining area designations were completed on July 17, 2018. State implementation of the revised NAAQS could result in stricter permitting requirements, delay or prohibit our ability to obtain such permits, and result in increased expenditures for pollution control equipment, the costs of which could be significant.
Compliance with these and other air pollution control and permitting requirements has the potential to delay the development of oil and natural gas projects and increase costs for us and our customers. Although we do not believe our operations will be materially adversely affected by these requirements, our business could be materially affected if our customers’ operations are significantly affected by these or other similar requirements. These requirements could increase the cost of doing business for us and our customers, reduce the demand for the oil and gas our customers produce, and thus have an adverse effect on the demand for our products and services.
Climate Change
More stringent laws and regulations relating to climate change may be adopted in the future and could cause us to incur additional operating costs or reduce the demand for our services. The EPA has determined that emissions of carbon dioxide, methane, and other greenhouse gases (“GHGs”) present an endangerment to the environment because emissions of such gases are, according to the EPA and many scientists, contributing to the warming of the earth’s atmosphere and other climatic changes. Based on these findings, EPA has adopted regulations that restrict emissions of GHGs under existing provisions of the CAA, including rules that require preconstruction and operating permit reviews for GHG emissions from certain large stationary sources. In subsequent litigation, the U.S. Supreme Court upheld a portion of the EPA’s GHG stationary source program, but also invalidated a portion of it, holding that stationary sources already subject to the Prevention of Significant Deterioration ("PSD") or Title V program for non-GHG criteria pollutants remained subject to GHG requirements, but that sources subject to the PSD or Title V program only for GHGs could not be forced to comply with EPA’s GHG requirements. Upon remand, the D.C. Circuit issued an amended judgment, which, among other things, vacated the GHG regulations under review in that case to the extent they require a stationary source to obtain a PSD or Title V permit solely because the source emits or has the potential to emit GHGs above the applicable major source thresholds. In October 2016, the EPA issued a proposed rule to further revise its PSD and Title V regulations applicable to GHGs in accordance with these court rulings. This rulemaking process is ongoing. The EPA has also adopted rules requiring the monitoring and reporting of GHG emissions from specified GHG sources, including, among others, certain oil and natural gas production facilities, on an annual basis. More recently, in June 2016, the EPA issued final rules that establish new air emission controls for emissions of methane from certain equipment and processes in the oil and natural gas source category, including production, processing transmission and storage activities. The EPA’s final rule package includes first-time standards to address emissions of methane from equipment and processes across the source category, including hydraulically fractured oil and natural gas well completions. However, over the past year the EPA has taken several steps to delay implementation of these methane rules, and the agency proposed a rulemaking in June 2017 to stay the requirements for a period of two years and revisit implementation of the EPA’s methane rules in their entirety. EPA proposed revisions on September 11, 2018, intended to roll back parts of the 2016 rules. The EPA has not yet published a final rule but, as a result of these developments, future implementation of the EPA methane rules is uncertain at this time. In April 2018, a coalition of states filed a lawsuit in federal district court aiming to force the EPA to establish guidelines for limiting methane emissions from existing sources in the oil and natural gas sector; that lawsuit is pending. In addition, the EPA finalized rules to further reduce GHG emissions, primarily from coal-fired power plants, under its Clean Power Plan. However, on October 9, 2017, the EPA announced that it will repeal the Clean Power Plan and, on August 21, 2018, proposed the Affordable Clean Energy ("ACE") rule, which would establish emission guidelines for states to develop plans to address greenhouse gas emissions from existing coal-fired power plants. The ACE rule would replace the Clean Power Plan and the rulemaking process is ongoing. The Bureau of Land Management (“BLM”) also finalized similar rules in November 2016 which seek to limit methane emissions from new and existing oil and gas operations on federal lands through limitations on the venting and flaring of gas, as well as enhanced leak detection and repair requirements for certain equipment and processes. In September 2018, the BLM issued a rule that relaxes or rescinds certain requirements of these regulations; California and New Mexico have challenged the new rule in ongoing litigation. We do not believe our operations are currently subject to these requirements, but, to the extent fully implemented, our business could be affected if our customers’ operations become subject to these or other similar requirements. Moreover, these requirements could increase the cost of doing business for us and our customers, reduce the demand for the oil and gas our customers produce, and thus have a material adverse effect on the demand for our products and services.
In addition, while Congress has yet to pass legislation to reduce emissions of GHGs, and almost one-half of the states have established or joined GHG cap and trade programs. Most of these cap and trade programs work by requiring major sources of emissions or major producers of fuels, to acquire and surrender emission allowances. The number of allowances available for purchase is reduced each year in an effort to achieve the overall greenhouse gas emission reduction goal. In addition, in 2015, the U.S. participated in the United Nations Conference on Climate Change, which led to the creation of the Paris Agreement. The Paris Agreement requires countries to review and “represent a progression” in their intended nationally determined contributions, which set GHG emission reduction goals, every five years beginning in 2020. However, in August 2017, the U.S. State Department officially informed the United Nations of the intent of the United States to withdraw from the Paris Agreement. The Paris Agreement has a four year exit process. The United States’ adherence to the exit process is uncertain and/or the terms on which the United States may reenter the Paris Agreement or a separately negotiated agreement are
unclear at this time. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any new federal, regional or state restrictions on emissions of carbon dioxide or other GHGs that may be imposed in areas in which we conduct business could result in increased compliance costs or additional operating restrictions on our customers. Such restrictions could potentially make our customers’ products more expensive and thus reduce demand for such products, which in turn could have a material adverse effect on the demand for our services and our business. Recently, activists concerned about the potential effects of climate change have directed their attention at sources of funding for fossil-fuel energy companies, which has resulted in certain financial institutions, funds and other sources of capital restricting or eliminating their investment in oil and natural gas activities. Ultimately, this could make it more difficult to secure funding for exploration and production activities, which could have a material adverse effect on our business and results of operations. Moreover, incentives to conserve energy or use alternative energy sources as a means of addressing climate change could reduce demand for the oil and natural gas our customers produce. Finally, it should be noted that many scientists have concluded that increasing concentrations of GHGs in the earth’s atmosphere may produce climatic changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic events; if any such effects were to occur, they could have an adverse effect on our assets and operations.
Hydraulic Fracturing
Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, sand and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production. We commonly perform hydraulic fracturing services for our customers. Hydraulic fracturing typically is regulated by state oil and natural gas commissions, but, as noted above, the EPA has asserted federal regulatory authority pursuant to the SDWA over certain hydraulic fracturing activities involving the use of diesel fuel and issued permitting guidance in February 2014 that applies to such activities. In addition, the EPA has taken certain actions noted above and issued final regulations under the CAA governing performance standards, including standards for the capture of air emissions released during hydraulic fracturing; and finalized rules in June 2016 to prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants, compliance with which is required by August 2019. Also, the BLM finalized rules in March 2015 that impose new or more stringent standards for performing hydraulic fracturing on federal and Native American lands. The BLM issued a final rule in December 2017 repealing its hydraulic fracturing rule, and this action has been challenged in federal court. Also, in December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources. The final report concluded that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources “under some circumstances,” noting that the following hydraulic fracturing water cycle activities and local- or regional-scale factors are more likely than others to result in more frequent or more severe impacts: water withdrawals for fracturing in times or areas of low water availability; surface spills during the management of fracturing fluids, chemicals or produced water; injection of fracturing fluids into wells with inadequate mechanical integrity; injection of fracturing fluids directly into groundwater resources; discharge of inadequately treated fracturing wastewater to surface waters; and disposal or storage of fracturing wastewater in unlined pits.
In addition, various state and local governments have implemented, or are considering, increased regulatory oversight of hydraulic fracturing through additional permit requirements, operational restrictions, disclosure requirements, well construction and temporary or permanent bans on hydraulic fracturing in certain areas. For example, in May 2013, the Texas Railroad Commission adopted new rules governing well casing, cementing and other standards for ensuring that hydraulic fracturing operations do not contaminate nearby water resources. In light of concerns about seismic activity being triggered by the injection of produced waters into underground wells, certain regulators are also considering additional requirements related to seismic safety for hydraulic fracturing activities. A 2015 U.S. Geological Survey report identified eight states with areas of increased rates of induced seismicity that could be attributed to fluid injection or oil and gas extraction. Any regulation that restricts the ability to dispose of produced waters or increases the cost of doing business could cause curtailed or decreased demand for our services and have a material adverse effect on our business. Local governments also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular or prohibit the performance of well drilling in general or hydraulic fracturing in particular. We believe that we follow applicable standard industry practices and legal requirements for groundwater protection in our hydraulic fracturing activities. If new federal, state or local laws or regulations that significantly restrict hydraulic fracturing are adopted, such legal requirements could result in delays, eliminate certain drilling and injection activities and make it more difficult or costly to perform hydraulic fracturing. Any such regulations limiting or prohibiting hydraulic fracturing could result in decreased oil and natural gas exploration and production activities and, therefore, adversely affect demand for our services and our business. Such laws or regulations could also materially increase our costs of compliance and doing business. The Endangered Species Act was established to protect endangered and threatened species. Pursuant to that act, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species or its habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. The U.S. Fish and Wildlife Service must also
designate the species’ critical habitat and suitable habitat as part of the effort to ensure survival of the species. A critical habitat or suitable habitat designation could result in further material restrictions to land use and may materially delay or prohibit land access for oil and natural gas development. If our customers were to have areas within their business and operations designated as critical or suitable habitat or a protected species, it could decrease demand for our services and have a material adverse effect on our business.
There have been no material incidents or citations related to our hydraulic fracturing operations in the past five years. During that period, we have not been involved in any litigation over alleged environmental violations, have not been ordered to pay any material monetary fine or penalty with respect to alleged environmental violations, and are not currently facing any type of governmental enforcement action or other regulatory proceeding involving alleged environmental violations related to our hydraulic fracturing operations. In addition, pursuant to our MSAs, we are generally liable for only surface pollution, not underground or flowback pollution, which our customers are generally liable for and for which we are typically indemnified by our customers.
We maintain insurance against some risks associated with underground contamination that may occur as a result of well services activities. However, this insurance is limited to activities at the well site and may not continue to be available or may not be available at premium levels that justify its purchase. The occurrence of a significant event not fully insured or indemnified against could have a materially adverse effect on our financial condition and results of operations.
Overall, we do not anticipate that compliance with existing environmental laws and regulations will have a material effect on our financial condition or results of operations. It is possible, however, that substantial costs for compliance or penalties for non-compliance may be incurred in the future. Moreover, it is possible that other developments, such as the adoption of stricter environmental laws, regulations, and enforcement policies, could result in additional costs or liabilities that we cannot currently quantify.
Item 1A.
Item 1A. Risk Factors
We face many challenges and risks in the industry in which we operate. Before investing in our common stock you should carefully consider each of the following risk factors and all of the other information set forth in this Annual Report, including under the section titled “Cautionary Note Regarding Forward-Looking Statements”, and in our other reports filed with the SEC, and the documents and other information incorporated by reference herein and therein, for a detailed discussion of known material factors which could materially affect our business, financial condition or future results. The risks and uncertainties described are not the only ones we face. Additional risk factors not presently known to us or which we currently consider immaterial may also adversely affect our business, financial condition or future results. If any of these risks were actually to occur, our business, financial condition or results of operations could be materially adversely affected. In that case, the trading price of our common stock could decline, and you could lose all or part of your investment.
Risks Related to Our Business and Financial Condition
Our business is cyclical and dependent upon conditions in the oil and natural gas industry that impact the level of exploration, development and production of oil and natural gas and capital expenditures by oil and natural gas companies. Our customers’ willingness to undertake drilling, completion and production activities depends largely upon prevailing industry conditions that are influenced by numerous factors that are beyond our control. Any of these factors could have a material adverse effect on our business, financial condition, results of operations and cash flow.
We depend on our customers’ willingness to make operating and capital expenditures to explore for, develop and produce oil and natural gas. If these expenditures decline, our business will suffer. The oil and gas industry has traditionally been volatile, is highly sensitive to supply and demand cycles and is influenced by a combination of long-term, short-term and cyclical trends. Our customers’ willingness to conduct drilling, completion and production activities depends largely upon prevailing industry conditions that are influenced by numerous factors over which we have no control, such as:
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the supply of and demand for oil and natural gas;
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the current and expected future prices for oil and natural gas and the perceived stability and sustainability of those prices;
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the supply of and demand for hydraulic fracturing and other well service equipment in the continental United States;
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the level of global and domestic oil and natural gas inventories;
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the cost of exploring for, developing, producing and delivering oil and natural gas;
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the ability or willingness of the Organization of Petroleum Exporting Countries (“OPEC”) to set and maintain production levels for oil;
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public pressure on, and legislative and regulatory interest within, federal, state and local governments to stop, significantly limit or regulate hydraulic fracturing activities;
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the expected rates of decline of current oil and natural gas production;
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lead times associated with acquiring equipment and products and availability of personnel;
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regulation of drilling activity;
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the availability of water resources, suitable proppant and chemicals in sufficient quantities for use in hydraulic fracturing fluids;
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the discovery and development rates of new oil and natural gas reserves;
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available pipeline and other transportation capacity;
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weather conditions, including hurricanes that can affect oil and natural gas operations over a wide area;
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political instability in oil and natural gas producing countries, including governmental shutdowns;
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domestic and worldwide economic conditions;
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technical advances affecting energy consumption;
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the price and availability of alternative fuels; and
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merger and divestiture activity among oil and natural gas producers.
Volatility or weakness in oil prices or natural gas prices (or the perception that oil prices or natural gas prices will decline) 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 less risk tolerant 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 core service lines, which could have a material adverse effect on our business, financial condition, results of operations and cash flows.
Spending by exploration and production companies can also be impacted by conditions in the capital markets. Limitations on the availability of capital, or higher costs of capital, for financing expenditures may cause exploration and production companies to make additional reductions to capital budgets in the future even if oil prices remain at current levels or natural gas prices increase from current levels. Any such cuts in spending may cause our customers to curtail their drilling programs, including completion and production activities and any discretionary spending on well services, which may result in a reduction in the demand for our services, the rates we can charge and the utilization of our assets. Moreover, reduced discovery rates of new oil and natural gas reserves, or a decrease in the development rate of reserves, in our market areas, whether due to increased governmental regulation, limitations on exploration and drilling activity or other factors, could also have a material adverse impact on our business, even in a stronger oil and natural gas price environment.
Fluctuations in oil and natural gas prices could adversely affect drilling, completion and production activities by oil and natural gas companies and our revenues, cash flows and profitability. If oil and natural gas prices remain volatile, or if oil or natural gas prices decline, the demand for our services could be adversely affected.
The demand for our services depends on the level of spending by oil and 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 so. For example, during 2018, NYMEX crude oil prices averaged approximately $65.00 per barrel, and during 2018 NYMEX crude oil prices ranged from approximately $76.00 to $43.00 per barrel. During periods of declining oil and natural gas prices, or when pricing remains depressed, we have experienced significant declines in drilling, completion and production activities across our customer base, which in turn resulted in reduced demand and increased competition and pricing pressure to varying degrees across our service lines and operating areas. If the prices of oil and natural gas continue to be weak and volatile, our business, financial condition, results of operations, cash flows and prospects may be materially and adversely affected.
Worldwide military, political and economic events, including initiatives by OPEC, affect both the demand for, and the supply of, oil and natural gas. Weather conditions, governmental regulation (both in the United States and elsewhere), levels of consumer demand, the availability of pipeline capacity and other factors that will be beyond our control may also affect the supply of, demand for, and price of oil and natural gas. Volatility or weakness in oil prices or natural gas prices (or the perception that oil prices or natural gas prices will decrease) affects the spending patterns of our customers and may result in the drilling of fewer new wells or lower completion and production spending on existing wells. This, in turn, could result in lower demand for our services and cause lower pricing and utilization levels for our services. If oil and natural gas prices decline, or if there is a further reduction in drilling and completion activities, the demand for our services and our results of operations could be materially and adversely affected.
The oilfield services industry is highly competitive with significant potential for excess capacity. We may not be able to meet the specific needs of oil and natural gas exploration and production companies at competitive prices which could adversely affect our business and operating results.
The oilfield services industry is highly competitive. The principal competitive factors in our markets are generally price, technical expertise, the availability and condition of equipment, work force capability, safety record, reputation and experience. We compete with large national and multi-national companies that have longer operating histories, greater financial resources and greater name recognition than we do and who can operate and have operated at a loss in the regions in which we operate. Additionally, some of our competitors provide a broader array of services and/or have a stronger presence in more geographic markets. Our reputation for safety and quality may not be sufficient to enable us to maintain our competitive position, and our competitors may be able to respond more quickly to new or emerging technologies and services and changes in customer requirements. As a result of competition, 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.
Increases in market capacity can lead to active price competition, which could adversely affect our business and utilization levels.
Significant increases in overall market capacity have caused active price competition and led to lower pricing and utilization levels for our services. Completion and well servicing equipment, such as hydraulic fracturing fleets, can be moved from one region to another in response to changes in levels of activity and market conditions, which may result in an oversupply of equipment in an area. For example, natural gas prices declined sharply in 2009 and remained depressed through 2015, which resulted in reduced drilling activity in natural gas shale plays. This drove many oilfield services companies operating in those areas to relocate their equipment to more oil- and liquids-rich shale plays, such as the Eagle Ford Shale and Permian Basin. As drilling activity and completion capacity migrated into the oil- and liquids-rich regions from the gas-rich
regions, the increase in supply relative to demand negatively impacted pricing and utilization of our services, particularly for hydraulic fracturing services. Furthermore, as we entered 2015, we experienced a slowdown in activity across our customer base as operators reacted to the rapid decline in commodity prices that began during the fourth quarter of 2014. The entire year proved to be extremely challenging for the North American oilfield services industry due to the sustained weakness and volatility in oil prices at levels that caused severe reductions in drilling, completion and production activities, which in turn resulted in reduced demand and increased competition and pricing pressure to varying degrees across our service lines and operating areas.
We may be unable to implement price increases or maintain existing prices on our core services.
We generate revenue from our core service lines, many of which are provided on a spot market basis. Pressure on pricing for our core services, including due to competition and industry and/or economic conditions, may impact, among other things, our ability to implement price increases or maintain pricing on our core services. We operate in a very competitive industry and, as a result, we may not always be successful in raising, or maintaining our existing prices. Additionally, during periods of increased market demand, a significant amount of new service capacity, including hydraulic fracturing equipment, may enter the market, which also puts pressure on the pricing of our services and limits our ability to increase or maintain prices. Furthermore, during periods of declining pricing for our services, we may not be able to reduce our costs accordingly, which could further adversely affect our profitability.
Even when we are able to increase our prices, we may not be able to do so at a rate that is sufficient to offset such rising costs. Also, we may not be able to successfully increase prices without adversely affecting our activity levels. The inability to maintain our prices or to increase our prices as costs increase could have a material adverse effect on our business, financial position and results of operations.
Reliance upon a few large customers may adversely affect our revenue and operating results.
Our top ten customers represented approximately 44.2%, 40.7% and 46.0% of our consolidated revenue for the years ended December 31, 2017, 2016 and 2015, respectively. It is likely that we will continue to derive a significant portion of our revenue from a relatively small number of customers in the future. If a major customer fails to pay us, revenue would be impacted, and our operating results and financial condition could be harmed. Additionally, if we were to lose any material customer, we may not be able to redeploy our equipment at similar utilization or pricing levels and such loss could have a material adverse effect on our business until the equipment is redeployed at similar utilization or pricing levels.
Weather conditions could materially impair our business.
Our operations and the operations of our customers may be adversely affected by seasonal weather conditions, severe weather events and natural disasters. For example, prolonged periods of drought, hurricanes, tropical storms, heavy snow, ice or rain may result in customer delays and other disruptions to our services. Repercussions of adverse weather conditions may include:
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curtailment of services;
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weather-related damage to facilities and equipment, resulting in suspension of operations;
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inability to deliver equipment, personnel and products to job sites in accordance with contract schedules;
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increase in the price of insurance; and
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loss of productivity.
These constraints could also delay our operations, reduce our revenue and materially increase our operating and capital costs.
Our operations are subject to hazards inherent in the oilfield services industry.
Risks inherent to our industry, such as equipment defects, vehicle accidents, explosions and uncontrollable flows of gas or well fluids, can cause personal injury, loss of life, suspension of operations, damage to formations, damage to facilities, business interruption and damage to, or destruction of property, equipment and the environment. For example, transportation of heavy equipment creates the potential for our trucks to become involved in roadway accidents, which in turn could result in personal injury or property damages lawsuits being filed against us. In addition, our hydraulic fracturing and well completion services could become a source of spills or releases of fluids, including chemicals used during hydraulic fracturing activities, at the site where such services are performed, or could result in the discharge of such fluids into underground formations that were not targeted for fracturing or well completion activities, such as potable aquifers. These risks could expose us to substantial liability for personal injury, wrongful death, property damage, loss of oil and natural gas production, pollution and other environmental damages and could result in a variety of claims, losses and remedial obligations that could have a material
adverse effect on our business and results of operations. The existence, frequency and severity of such incidents will affect operating costs, insurability and relationships with customers, employees and regulators. In particular, our customers may elect not to purchase our services if they view our safety record as unacceptable, which could cause us to lose customers and substantial revenue.
Our operational personnel have experienced accidents which have, in some instances, resulted in serious injuries. Our safety procedures may not always prevent such damages. Our insurance coverage may be inadequate to cover our liabilities. In addition, we may not be able to maintain adequate insurance in the future at rates we consider reasonable and commercially justifiable or on terms as favorable as our current arrangements. The occurrence of a significant uninsured claim, a claim in excess of the insurance coverage limits maintained by us or a claim at a time when we are not able to obtain liability insurance could have a material adverse effect on our ability to conduct normal business operations and on our financial condition, results of operations and cash flows.
Unsatisfactory safety performance may negatively affect our customer relationships and, to the extent we fail to retain existing customers or attract new customers, adversely impact our revenues.
Our ability to retain existing customers and attract new business is dependent on many factors, including our ability to demonstrate that we can reliably and safely operate our business in a manner that is consistent with applicable laws, rules and permits, which legal requirements are subject to change. Existing and potential customers consider the safety record of their third-party service providers to be of high importance in their decision to engage such providers. If one or more accidents were to occur at one of our operating sites, the affected customer may seek to terminate or cancel its use of our facilities or services and may be less likely to continue to use our services, which could cause us to lose substantial revenues. Furthermore, our ability to attract new customers may be impaired if they elect not to engage us because they view our safety record as unacceptable. In addition, it is possible that we will experience multiple or particularly severe accidents in the future, causing our safety record to deteriorate. This may be more likely as we continue to grow, if we experience high employee turnover or labor shortage, or hire inexperienced personnel to bolster our staffing needs.
We may be unable to employ a sufficient number of key employees, technical personnel and other skilled and 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 in fields that offer a different work environment. Our ability to be productive and profitable depends upon our ability to employ and retain skilled workers. In addition, our ability to expand our operations depends in part on our ability to increase the size of our skilled labor force. At times, demand for skilled workers in our geographic area of operations is high, and the supply is limited. 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 pay, or both. If either of these events were to occur, our capacity and profitability could be diminished, and our growth potential could be impaired.
We depend heavily on the efforts of our 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.
Delays in deliveries of key raw materials or increases in the cost of key raw materials could harm our business, results of operations and financial condition.
We have established relationships with a limited number of suppliers of our raw materials (such as proppant, guar, chemicals or coiled tubing) and finished products (such as fluid-handling equipment). Should any of our current suppliers be unable to provide the necessary raw materials or finished products or otherwise fail to deliver the products in a timely manner and in the quantities required, any resulting delays in the provision of services could have a material adverse effect on our business, financial condition, results of operations and cash flows. Additionally, increasing costs of certain raw materials, including guar, may negatively impact demand for our services or the profitability of our business operations. In the past, our industry faced sporadic shortages associated with hydraulic fracturing operations, such as proppant and guar, requiring work stoppages, which adversely impacted the operating results of several competitors. We may not be able to mitigate any future shortages of raw materials, including proppants.
We may be adversely affected by uncertainty in the global financial markets and the deterioration of the financial condition of our customers.
Our future results may be impacted by the uncertainty caused by an economic downturn, volatility or deterioration in the debt and equity capital markets, inflation, deflation or other adverse economic conditions that may negatively affect us or parties with whom we do business resulting in a reduction in our customers’ spending and their non-payment or inability to perform obligations owed to us, such as the failure of customers to honor their commitments or the failure of major suppliers to complete orders. Additionally, during times when the natural gas or crude oil markets weaken, our customers are more likely to experience financial difficulties, including being unable to access debt or equity financing, which could result in a reduction in our customers’ spending for our services. In addition, in the course of our business we hold accounts receivable from our customers. In the event of the financial distress or bankruptcy of a customer, we could lose all or a portion of such outstanding accounts receivable associated with that customer. Further, if a customer was to enter into bankruptcy, it could also result in the cancellation of all or a portion of our service contracts with such customer at significant expense or loss of expected revenues to us.
Our assets require significant amounts of capital for maintenance, upgrades and refurbishment and may require significant capital expenditures for new equipment.
Our hydraulic fracturing fleets and other completion service-related equipment require significant capital investment in maintenance, upgrades and refurbishment to maintain their competitiveness. The costs of components and labor required to maintain our fleets have increased in the past and may increase in the future with increases in demand, which will require us to incur additional costs to make our remaining active fleets operational. Our fleets and other equipment typically do not generate revenue while they are undergoing maintenance, refurbishment or upgrades. Any maintenance, upgrade or refurbishment project for our assets could increase our indebtedness or reduce cash available for other opportunities. Further, such projects may require proportionally greater capital investments as a percentage of total asset value, which may make such projects difficult to finance on acceptable terms. To the extent we are unable to fund such projects, we may have less equipment available for service or our equipment may not be attractive to potential or current customers. Additionally, 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 hydraulic fracturing fleets and other completion service related equipment and the increase in cost to maintain labor necessary for such maintenance and improvement, in each case, could have a material adverse effect on our business, liquidity position, financial condition, prospects and results of operations and may increase the cost to make our inactive fleets operational.
We participate in a capital-intensive industry, and we may not be able to finance future growth of our operations or future acquisitions, which could adversely affect our operations and financial position.
The successful execution of our growth strategy depends on our ability to generate sufficient cash flows and our access to capital, both of which are impacted by numerous factors beyond our control, including financial, business, economic and other factors, such as volatility in commodity prices and pressure from competitors. Disruptions in the capital and credit markets, in particular with respect to companies in the energy sector, could limit our ability to access these markets or may significantly increase our cost to borrow. Continued low commodity prices, among other factors, have caused some lenders to increase interest rates, enact tighter lending standards which we may not satisfy as a result of our debt level or otherwise, refuse to refinance existing debt at maturity on favorable terms or at all, and in certain instances have reduced or ceased to provide funding to borrowers.
If we are unable to generate sufficient cash flows or to access the capital and credit markets on favorable terms or at all, we may be unable to continue growing our business, conduct necessary corporate activities, take advantage of business opportunities that arise or engage in activities that may be in our long-term best interest, which may adversely impact our ability to sustain or improve our current level of profitability. Furthermore, any failure to make scheduled payments of interest and principal on our outstanding indebtedness could harm our ability to incur additional indebtedness on acceptable terms or at all, and also could constitute an event of default under our Credit Facility. Our inability to generate sufficient cash flow to satisfy our debt obligations or to obtain alternative financing could materially and adversely affect our business, financial condition, results of operations, cash flows and prospects, and we could be forced into bankruptcy or liquidation.
Disruptions in the capital and credit markets, continued low commodity prices, our debt level and other factors may restrict our ability to raise capital on favorable terms, or at all.
Disruptions in the capital and credit markets, in particular with respect to companies in the energy sector, could limit our ability to access these markets or may significantly increase our cost to borrow. Continued low commodity prices, among other factors, have caused some lenders to increase interest rates, enact tighter lending standards which we may not satisfy as a result of our debt level or otherwise, refuse to refinance existing debt at maturity on favorable terms, or at all, and in
certain instances have reduced or ceased to provide funding to borrowers. If we are unable to access the capital and credit markets on favorable terms or at all, it could adversely affect our business, financial condition and results of operations.
We are subject to restrictive covenants in our Credit Facility, which may restrict our operational flexibility.
The Credit Facility governing our indebtedness contains, and future debt agreements may contain, financial and other restrictive covenants that may limit our ability to obtain future financings to withstand a future downturn in our business or the economy in general, conduct necessary corporate activities, take advantage of business opportunities that arise and/or to engage in activities that may be in our long-term best interests.
Specifically, our Credit Facility includes a Fixed Charge Coverage Ratio and minimum liquidity threshold covenants and restrictive covenants that limit our ability and that of our subsidiaries to, among other things:
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sell or otherwise dispose of assets;
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make certain restricted payments and investments;
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create, incur, assume, suffer to exist or guarantee additional indebtedness;
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create, incur, assume, or suffer to exist liens on our assets;
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make capital expenditures, investments or acquisitions;
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repurchase, redeem or retire our capital shares;
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merge or consolidate, or transfer all or substantially all of our assets and the assets of our subsidiaries;
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engage in specified transactions with subsidiaries and affiliates; and
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pursue other corporate activities.
We may be prevented from taking advantage of business opportunities that arise because of the limitations imposed on us by restrictive covenants under the Credit Facility, which could: limit our ability to plan for, or react to, market conditions, to meet capital needs or otherwise restrict our activities or business plan; and adversely affect our ability to finance our operations, enter into acquisitions or to engage in other business activities that would be in our interest.
Please see “Liquidity and Capital Resources - Description of Our Indebtedness - Credit Facility” in Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for additional information about the Credit Facility, including the financial and other restrictive covenants contained therein.
We may not be able to service our debt obligations in accordance with their terms.
On May 1, 2018, we entered into a new asset-based revolving credit agreement (the “Credit Facility”). Our ability to meet our debt service obligations under, and comply with the financial covenants contained in, our Credit Facility or future debt agreements depends on our future performance, which is affected by financial, business, economic and other factors, many of which are beyond our control, including volatility in commodity prices and pressure from competitors. Should our revenues decline, we may not be able to generate sufficient cash flow to pay our debt service obligations when due. Additionally, revenue, utilization and pricing level declines may result in our not being in compliance with one or more of the financial covenants under our Credit Facility or future debt agreements in future periods. Any failure to satisfy our debt obligations or to comply with the applicable financial covenants could materially and adversely affect our business, financial condition, results of operations, cash flows and prospects.
If we are unable to meet our debt service obligations or should we fail to comply with, or obtain relief from, the financial and other restrictive covenants contained in our Credit Facility or future debt agreements, we may trigger an event of default. Upon such an event of default, our lenders may refuse to fund borrowings and have the right to terminate their commitments and potentially accelerate all of our outstanding debt. If an event of default occurs and the lenders under our Credit Facility or future debt agreements accelerate the maturity of any loans or other debt outstanding. We may not be able to make all required payments or borrow sufficient funds to refinance such indebtedness. Even if new financing is available at that time it may not be on terms that are acceptable to us.
Any reduction of the borrowing base under our Credit Facility could require us to repay that portion of indebtedness that exceeds the new borrowing base under our Credit Facility earlier than anticipated, which could adversely impact our liquidity.
Our Credit Facility allows us to borrow amounts up to the lesser of $400 million and a borrowing base based on the value of our eligible accounts receivable, inventory and restricted cash. Currently, our borrowing base is $234.7 million. Reductions in accounts receivable and inventory due to events or market forces beyond our control could reduce the amount available to us under our Credit Facility and could result in a redetermination, and potentially a reduction, of our borrowing
bases under our Credit Facility. If our Credit Facility eventually becomes fully drawn, any reduction in the borrowing bases could require us to make mandatory prepayments under our Credit Facility to the extent existing indebtedness under the Credit Facility exceeds the borrowing base. We may have insufficient cash on hand to be able to make mandatory prepayments under our Credit Facility. Any failure to repay indebtedness in excess of our borrowing bases in accordance with the terms of the Credit Facility would constitute an event of default under the Credit Facility. Such event of default would permit our lenders to accelerate our outstanding debt, which if actually accelerated, would become immediately due and payable and could permit our secured lenders to foreclose on any of our assets securing indebtedness.
As a result of the implementation of our Restructuring Plan, we believe our ability to use net operating loss carryforwards to offset future taxable income for U.S. federal income tax purposes may be subject to limitation under Section 382.
Under U.S. federal income tax law, a corporation is generally permitted to deduct from taxable income net operating losses (“NOLs”) carried forward from prior years. As of December 31, 2018, we reported consolidated federal NOL carryforwards of approximately $1.3 billion of which $454.8 million are pre-change NOL's subject to limitation. Our ability to utilize our NOL carryforwards to offset future taxable income and to reduce U.S. federal income tax liability is subject to certain requirements and restrictions. In general, under Section 382 of the Internal Revenue Code of 1986, as amended (the “Code”), a corporation that undergoes an “ownership change” is subject to limitations on its ability to utilize its pre-change NOLs to offset future taxable income. An ownership change generally occurs if one or more shareholders (or groups of shareholders) who are each deemed to own at least 5% of our stock have aggregate increases in their ownership of such stock of more than 50 percentage points over such stockholders’ lowest ownership percentage during the testing period (generally a rolling three year period). We believe we experienced an ownership change in January 2017 as a result of the implementation of the Restructuring Plan and that our pre-change NOLs are subject to limitation under Section 382 of the Code as a result. Such limitation may cause U.S. federal income taxes to be paid earlier than otherwise would be paid if such limitation were not in effect and could cause our pre-change NOLs to expire unused, in each case reducing or eliminating the benefit of such NOLs. Similar rules and limitations may apply for state income tax purposes.
As a result of the implementation of our Restructuring Plan, NOLs and other tax attributes may be subject to reduction, causing less NOL or tax deductions to be available to offset future taxable income for U.S. federal income tax purposes.
As a result of consummating our Restructuring Plan, the obligations of the Predecessor with respect to the Original Credit Agreement (the “Old C&J Debt”) were canceled and discharged and certain lenders were issued common stock in the reorganized Company (See Note 14 - Chapter 11 Proceeding and Emergence). This exchange may give rise to cancellation of debt income (“CODI”) to the extent that the fair market value of the common stock and other rights exchanged with the lenders is less than the adjusted issue price of the Old C&J Debt. Other settlements with holders of Claims under the Restructuring Plan may have resulted in satisfaction of debts for less than the amount of the liability resulting in CODI. The Code provides that CODI arising under a discharge in a Chapter 11 bankruptcy proceeding is excluded from taxable income. A taxpayer excluding CODI under these circumstances may be required to reduce certain tax attributes, such as NOLs and depreciable basis by an amount up to the amount of excluded CODI (the “Tax Attribute Reduction Rules”). As of December 31, 2018, there are a number of significant claims under the Restructuring Plan that remain outstanding. We will continue to monitor these claims and make estimates accordingly.
We are vulnerable to the potential difficulties associated with growth, mergers, acquisitions and expansion.
We believe that our future success depends on our ability to take advantage of and manage rapid growth, as well as the demands from increased responsibility on our management personnel. The following factors could present difficulties to us:
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lack of sufficient executive-level personnel;
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increased administrative burden;
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long lead times associated with acquiring additional equipment;
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ability to manage significant levels of idle equipment in sustained periods of depressed oil and natural gas prices;
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ability to maintain the level of focused service attention that we have historically been able to provide to our customers; and
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new or expanded areas of operational risk (such as offshore or international operations) and related costs and demands of any applicable regulatory compliance.
In addition, in the future we may seek to grow our business through acquisitions that enhance our existing operations. The success of any completed acquisition will depend on our ability to integrate effectively the acquired business into our existing operations. The process of integrating acquired businesses may involve unforeseen difficulties and may
require a disproportionate amount of our managerial and financial resources. Our operating results could be adversely affected if we do not successfully manage these potential difficulties in integrating the businesses we may acquire.
Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays as well as adversely affect demand for our support services.
Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, sand and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production. We commonly perform hydraulic fracturing services for our customers.
Hydraulic fracturing typically is regulated by state oil and natural gas commissions, but the EPA has asserted federal regulatory authority pursuant to the SDWA over certain hydraulic fracturing activities involving the use of diesel fuel and issued permitting guidance in February 2014 that applies to such activities. Also, in May 2014, the EPA published an advanced notice of proposed rulemaking under the Toxic Substances and Control Act (“TSCA”) that would require the disclosure of chemicals used in hydraulic fracturing fluids; however, to date no further action has been taken and additional rulemaking under TSCA appears unlikely at this time. In addition, in June 2016, the EPA finalized regulations that prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants.
In December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources. The final report concluded that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources under some circumstances,” noting that the following hydraulic fracturing water cycle activities and local- or regional-scale factors are more likely than others to result in more frequent or more severe impacts: water withdrawals for fracturing in times or areas of low water availability; surface spills during the management of fracturing fluids, chemicals or produced water; injection of fracturing fluids into wells with inadequate mechanical integrity; injection of fracturing fluids directly into groundwater resources; discharge of inadequately treated fracturing wastewater to surface waters; and disposal or storage of fracturing wastewater in unlined pits. Since the report did not find a direct link between hydraulic fracturing itself and contamination of groundwater resources, this years-long study report does not appear to provide any basis for further regulation of hydraulic fracturing at the federal level.
Various state and local governments have implemented, or are considering, increased regulatory oversight of hydraulic fracturing through additional permit requirements, operational restrictions, disclosure requirements, well construction, and temporary or permanent bans on hydraulic fracturing in certain areas. For example, in May 2013, the Texas Railroad Commission adopted new rules governing well casing, cementing and other standards for ensuring that hydraulic fracturing operations do not contaminate nearby water resources. In addition, state and federal regulatory agencies have recently focused on a possible connection between the disposal of wastewater in underground injection wells and the increased occurrence of seismic activity, and regulatory agencies at all levels are continuing to study the possible linkage between oil and gas activity and induced seismicity. In response to these concerns, regulators in some states are seeking to impose additional requirements on hydraulic fracturing fluid disposal practices, including restrictions on the operations of produced water disposal wells and imposing more stringent requirements on the permitting of such wells. The adoption and implementation of any new laws or regulations that restrict our ability to dispose of produced water gathered from our customer’s activities by limiting volumes, disposal rates, disposal well locations or otherwise, or requiring us to shut down disposal wells, could have a material adverse effect on our fluid transportation business, financial condition and results of operations.
Local governments also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular or prohibit the performance of well drilling in general or hydraulic fracturing in particular. If new federal, state or local laws or regulations that significantly restrict hydraulic fracturing are adopted, such legal requirements could result in delays, eliminate certain drilling and injection activities and make it more difficult or costly to perform hydraulic fracturing. Any such regulations limiting or prohibiting hydraulic fracturing could result in decreased oil and natural gas exploration and production activities and, therefore, adversely affect demand for our services and our business. Such laws or regulations could also materially increase our costs of compliance and doing business.
The adoption of new laws or regulations imposing reporting obligations on, or otherwise limiting, the hydraulic fracturing process could make it more difficult to complete oil and natural gas wells in shale formations, increase our costs of compliance and adversely affect the hydraulic fracturing services that we render for our exploration and production customers. In addition, if hydraulic fracturing becomes regulated at the federal level as a result of federal legislation or regulatory initiatives by the EPA, fracturing activities could become subject to additional permitting requirements, and also to attendant permitting delays and potential increases in cost, which could adversely affect our business and results of operations.
Climate change legislation or regulations restricting emissions of GHGs could result in increased operating costs and reduced demand for our services.
The EPA has determined that emissions of carbon dioxide, methane and other GHGs present an endangerment to the environment because emissions of such gases are contributing to the warming of the earth’s atmosphere and other climatic changes. Based on these findings, the EPA adopted regulations that restrict emissions of GHGs under existing provisions of the federal Clean Air Act.
From time to time the U.S. Congress has considered legislation to reduce emissions of GHGs, and almost one-half of the states have established GHG cap and trade programs. Most of these cap and trade programs work by requiring major sources of emissions or major producers of fuels, to acquire and surrender emission allowances. The number of allowances available for purchase is reduced each year in an effort to achieve the overall greenhouse gas emission reduction goal.
Any new federal, regional or state restrictions on emissions of GHGs that may be imposed in areas in which we conduct business could result in increased compliance costs or additional operating restrictions on our customers. Such actions could also potentially make our customers’ products more expensive and thus reduce demand for those products, which could have a material adverse effect on the demand for our services and our business. Recently, activists concerned about the potential effects of climate change have directed their attention at sources of funding for fossil-fuel energy companies, which has resulted in certain financial institutions, funds and other sources of capital restricting or eliminating their investment in oil and natural gas activities. Ultimately, this could make it more difficult to secure funding for exploration and production activities, which could have a material adverse effect on our business and results of operations. Moreover, incentives to conserve energy or use alternative energy sources as a means of addressing climate change could reduce demand for the oil and natural gas our customers produce. Notwithstanding potential risks related to climate change, the International Energy Agency estimates that global energy demand will continue to rise and will not peak until after 2040 and that oil and gas will continue to represent a substantial percentage of global energy use over that time. Finally, many scientists have concluded that increasing concentrations of GHGs in the earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic events. If any such effects were to occur, they could have an adverse effect on our results of operations if they were to damage our equipment or facilities.
We are subject to extensive and costly environmental, and occupational health and safety laws, and regulations that may require us to take actions that will adversely affect our results of operations.
Our business is significantly affected by stringent and complex federal, state and local laws and regulations governing the emission or discharge of substances into the environment, protection of the environment and worker health and safety. Any failure by us to comply with such environmental and occupational health and safety laws and regulations may result in governmental authorities taking actions against our business that could adversely impact our operations and financial condition, including the following:
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issuance of administrative, civil and criminal penalties;
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modification, denial or revocation of permits or other authorizations;
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imposition of limitations on our operations or orders prohibiting our operations altogether; and
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performance of site investigatory, remedial or other corrective actions.
As part of our business, we handle, transport, and dispose of a variety of fluids and substances used by our customers in connection with their oil and natural gas exploration and production activities. We also generate and dispose of nonhazardous and hazardous wastes. The generation, handling, transportation, and disposal of these fluids, substances, and wastes are regulated by a number of laws, including CERCLA, RCRA, Clean Water Act, SDWA and analogous state laws. Under RCRA, the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes are regulated. RCRA currently exempts many exploration and production wastes from classification as hazardous waste. However, these oil and gas exploration and production wastes may still be regulated under state solid waste laws and regulations, and it is possible that certain oil and natural gas exploration and production wastes now classified as non-hazardous could be classified as hazardous waste in the future.
Failure to properly handle, transport or dispose of these materials or otherwise conduct our operations in accordance with these and other environmental laws could expose us to liability for governmental penalties, third-party claims, cleanup costs associated with releases of such materials, damages to natural resources, and other damages, as well as potentially impair our ability to conduct our operations. Moreover, certain of these environmental laws impose joint and several, strict liability even though our conduct in performing such activities was lawful at the time it occurred or the conduct of, or conditions caused by, prior operators or other third-parties was the basis for such liability. In addition, environmental laws and
regulations are subject to frequent change and if existing laws, regulatory requirements or enforcement policies were to change in the future, we may be required to make significant unanticipated capital and operating expenditures.
Anti-indemnity provisions enacted by many states may restrict or prohibit a party’s indemnification of us.
We typically enter into agreements with our customers governing the provision of our services, which usually include certain indemnification provisions for losses resulting from operations. Such agreements may require each party to indemnify the other against certain claims regardless of the negligence or other fault of the indemnified party; however, many states place limitations on contractual indemnity agreements, particularly agreements that indemnify a party against the consequences of its own negligence. Furthermore, certain states, including Texas, New Mexico and Wyoming, have enacted statutes generally referred to as “oilfield anti-indemnity acts” expressly prohibiting certain indemnity agreements contained in or related to oilfield services agreements. Such anti-indemnity acts may restrict or void a party’s indemnification of us, which could have a material adverse effect on our business, financial condition, prospects and results of operations.
New technology may hurt our competitive position.
The energy service industry is subject to the introduction of new techniques and services using new technologies, some of which may be subject to patent protection. As competitors and others use or develop new technologies or technologies comparable to ours in the future, we may lose market share or be placed at a competitive disadvantage. Further, 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 than we do, which may allow them to gain technological advantages or implement new technologies before we can. Additionally, we may be unable to implement new technologies or products at all, on a timely basis or at an acceptable cost. Limits on our ability to effectively use or implement new technologies may have a material adverse effect on our business, financial condition and results of operations.
We may be adversely affected by disputes regarding intellectual property rights and the value of our intellectual property rights is uncertain.
We may become involved in dispute resolution proceedings from time to time to protect and enforce our intellectual property rights. In these dispute resolution proceedings, a defendant may assert that our intellectual property rights are invalid or unenforceable. Third parties from time to time may also initiate dispute resolution proceedings against us by asserting that our businesses infringe, impair, misappropriate, dilute, or otherwise violate another party’s intellectual property rights. We may not prevail in any such dispute resolution proceedings, and our intellectual property rights may be found invalid or unenforceable or our products and services may be found to infringe, impair, misappropriate, dilute, or otherwise violate the intellectual property rights of others. The results or costs of any such dispute resolution proceedings may have an adverse effect on our business, operating results, and financial condition. Any dispute resolution proceeding concerning intellectual property could be protracted and costly, is inherently unpredictable, and could have an adverse effect on our business, regardless of its outcome.
Our success may be affected by the use and protection of our proprietary technology. There are limitations to our intellectual property rights and, thus, our right to exclude others from the use of such proprietary technology.
Our success may be affected by our development and implementation of new product designs and improvements and by our ability to protect, obtain, and maintain intellectual property assets related to these developments. We rely on a combination of patents and trade secret laws to establish and protect this proprietary technology. We have received patents and have filed patent applications with respect to certain aspects of our technology, and we generally rely on patent protection with respect to our proprietary technology, as well as a combination of trade secrets and copyright law, employee and third-party non-disclosure agreements, and other protective measures to protect intellectual property rights pertaining to our products and technologies. We cannot assure you that competitors will not infringe upon, misappropriate, violate, or challenge our intellectual property rights in the future. If we are not able to adequately protect or enforce our intellectual property rights, such intellectual property rights may not provide significant value to our business, results of operations, or financial condition.
Moreover, our rights in our confidential information, trade secrets, and confidential know-how will not prevent third parties from independently developing similar technologies or duplicating such technologies. Publicly available information (e.g., information in issued patents, published patent applications, and scientific literature) can be used by third parties to independently develop technology, and we cannot provide assurance that this independently developed technology will not be equivalent or superior to our proprietary technology. In addition, while we have patented some of our key technologies, we do not patent all of our proprietary technology, even when regarded as patentable. The process of seeking patent protection can be long and expensive. There can be no assurance that patents will be issued from currently pending or
future applications or that, if patents are issued, they will be of sufficient scope or strength to provide meaningful protection or any commercial advantage to us.
We are subject to certain requirements of Section 404 of the Sarbanes-Oxley Act. If we fail to comply with the requirements of Section 404 or if we or our auditors identify and report material weaknesses in internal control over financial reporting, our investors may lose confidence in our reported information and our stock price may be negatively affected.
As of December 31, 2018, we are required to comply with certain provisions of Section 404 of the Sarbanes-Oxley Act of 2002, or Sarbanes-Oxley Act. Section 404 requires that we document and test our internal control over financial reporting and issue our management’s assessment of our internal control over financial reporting. This section also requires that our independent registered public accounting firm issue an attestation report on such internal control. If we fail to comply with the requirements of Section 404 of the Sarbanes-Oxley Act, or if we or our auditors identify and report material weaknesses in our internal control over financial reporting, 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.
Our operations are subject to cyber-attacks or other cyber incidents that could have a material adverse effect on our business, consolidated results of operations, and consolidated financial condition.
We rely heavily on digital technologies and services. We use these technologies for internal purposes, including data storage (which may include personal identification information of our employees as well as our proprietary business information and that of our customers, suppliers, investors and other stakeholders), processing, and transmissions, as well as in our interactions with customers and suppliers. Digital technologies are subject to the risk of cyber-attacks, security breaches and other cyber incidents, which could include, among other things, computer viruses, malicious or destructive code, ransomware, social engineering attacks (including phishing and impersonation), hacking, denial-of-service attacks and other attacks and similar disruptions from the unauthorized use of or access to computer systems. If our systems for protecting against cybersecurity risks prove not to be sufficient, we could be adversely affected by, among other things: loss of or damage to intellectual property, proprietary or confidential information, or customer, supplier, or employee data; interruption of our business operations; and increased costs required to prevent, respond to, or mitigate cybersecurity attacks. These risks could harm our reputation and our relationships with customers, suppliers, employees, and other third-parties, and may result in claims against us, including liability under laws that protect the privacy of personal information. In addition, these risks could have a material adverse effect on our business, results of operations and financial condition.
Adoption of fresh start accounting beginning in the first quarter of 2017 limits the comparability of our current and future financial condition and results of operations to our financial condition and results of operations for periods prior to our emergence from the Chapter 11 Proceeding.
Upon our emergence from the Chapter 11 Proceeding, we adopted fresh start accounting in accordance with the provisions set forth in Accounting Standards Codification Topic 852 - Reorganizations. Our consolidated financial statements also reflect all of the transactions contemplated by the Restructuring Plan. Accordingly, our financial condition and results of operations subsequent to emergence are not comparable to the financial condition or results of operations reflected in our historical financial statements prior to emergence.
More stringent trucking regulations may increase our costs and negatively impact our results of operations.
As part of the services we provide, we operate as a motor carrier and therefore are subject to regulation by the DOT, and by other various state agencies. These regulatory authorities exercise broad powers, governing activities such as the authorization to engage in motor carrier operations and regulatory safety, and hazardous materials labeling, placarding and marking. There are additional regulations specifically relating to the trucking industry, including testing and specification of equipment and product handling requirements. In addition, the trucking industry is subject to possible regulatory and legislative changes that may affect the economics of the industry by requiring changes in operating practices or by changing the demand for common or contract carrier services or the cost of providing truckload services. Some of these possible changes include increasingly stringent environmental regulations, changes in the hours of service regulations which govern the amount of time a driver may drive in any specific period, require onboard black box recorder devices or limits on vehicle weight and size. For example, in December 2016, the DOT finalized minimum training standards for new drivers seeking a commercial driver’s license. Certain motor vehicle operators are required to register with the DOT. This registration requires an acceptable operating record. The DOT periodically conducts compliance reviews and may revoke registration privileges based on certain safety
performance criteria, and a revocation could result in a suspension of operations. Since 2010, the DOT has pursued its Compliance, Safety, Accountability (“CSA”) program, in an effort to improve commercial truck and bus safety. A component of CSA is the Safety Measurement System (“SMS”), which analyzes all safety violations recorded by federal and state law enforcement personnel to determine a carrier’s safety performance. The SMS is intended to allow DOT to identify carriers with safety issues and intervene to address those problems.
Interstate motor carrier operations are subject to safety requirements prescribed by the DOT. To a large degree, intrastate motor carrier operations are subject to state safety regulations that mirror federal regulations. Such matters as weight and dimension of equipment are also subject to federal and state regulations.
From time to time, various legislative proposals are introduced, including proposals to increase federal, state or local taxes, including taxes on motor fuels, which may increase our costs or adversely impact the recruitment of drivers. We cannot predict whether, or in what form, any increase in such taxes applicable to us will be enacted.
We could be adversely affected by violations of the U.S. Foreign Corrupt Practices Act and similar foreign anti-bribery laws.
The United States Foreign Corrupt Practices Act (the “FCPA”) and similar worldwide anti-bribery laws generally prohibit companies and their intermediaries and partners from making, offering or authorizing improper payments to non-U.S. government officials for the purpose of obtaining or retaining business. Although we currently have no international operations, we previously did business and may do business in the future in countries or regions where strict compliance with anti-bribery laws may conflict with local customs and practices. Our employees, intermediaries, and partners may face, directly or indirectly, corrupt demands by government officials, political parties and officials, tribal or insurgent organizations, or private entities in the countries in which we operate or may operate in the future. As a result, we face the risk that an unauthorized payment or offer of payment could be made by one of our employees, intermediaries, or partners even if such parties are not always subject to our control or are not themselves subject to the FCPA or other anti-bribery laws to which we may be subject. We are committed to doing business in accordance with applicable anti-bribery laws and have implemented policies and procedures concerning compliance with such laws. Our existing safeguards and any future improvements, however, may prove to be less than effective, and our employees, intermediaries, and partners may engage in conduct for which we might be held responsible. Violations of the FCPA and other anti-bribery laws (either due to our acts, the acts of our intermediaries or partners, or our inadvertence) may result in criminal and civil sanctions and could subject us to other liabilities in the U.S. and elsewhere. Even allegations of such violations could disrupt our business and result in a material adverse effect on our business and operations.
Risks Related to Our Common Stock
The concentration of our capital stock ownership among our largest stockholders and their affiliates will limit your ability to influence corporate matters.
A large percentage of our shares of common stock are held by a relatively small number of investors whose interests may conflict. Consequently, these holders (each of whom we refer to as a “principal stockholder”) may have significant influence over all matters that require approval by our stockholders, including the election of directors and approval of significant corporate transactions. This concentration of ownership and the rights of our principal stockholders will limit your ability to influence corporate matters and, as a result, actions may be taken that you may not view as beneficial.
Furthermore, conflicts of interest could arise in the future between us, on the one hand, and our principal stockholders and their respective affiliates, including portfolio companies, on the other hand, concerning among other things, potential competitive business activities or business opportunities. Several of our principal stockholders are private equity firms or investment funds in the business of making investments in entities in a variety of industries. As a result, our principal stockholders’ existing and future portfolio companies may compete with us for investment or business opportunities. These conflicts of interest may not be resolved in our favor.
Certain of our directors have significant duties with, and spend significant time serving, entities that may compete with us in seeking acquisitions and business opportunities and, accordingly, may have conflicts of interest in allocating time or pursuing business opportunities.
Certain of our directors, who are responsible for managing the direction of our operations and acquisition activities, hold positions of responsibility with other entities. The existing positions held by these directors may give rise to fiduciary or other duties that are in conflict with the duties they owe to us. These directors may become aware of business opportunities that may be appropriate for presentation to us as well as to the other entities with which they are or may become affiliated. Due to these existing and potential future affiliations, they may present potential business opportunities to other entities prior to
presenting them to us, which could cause additional conflicts of interest. They may also decide that certain opportunities are more appropriate for other entities with which they are affiliated and, as a result, they may elect not to present those opportunities to us. These conflicts may not be resolved in our favor.
Future sales or the availability for sale of substantial amounts of our common stock, or the perception that these sales may occur, could adversely affect the trading price of our common stock and could impair our ability to raise capital through future sales of equity securities.
Our Amended and Restated Certificate of Incorporation authorizes us to issue 1,000,000,000 shares of common stock, of which an estimated 66,062,430 shares were outstanding as of February 22, 2019. This number includes 55,463,903 shares issued in connection with our emergence from bankruptcy. We also have 8,046,021 shares of common stock authorized for issuance as equity awards under the 2017 C&J Energy Services, Inc. Management Incentive Plan, of which 351,306 shares are issuable pursuant to outstanding options, 941,341 shares are issuable pursuant to our outstanding restricted share units, 607,715 shares are issuable pursuant to outstanding restricted stock awards and 396,455 shares are issuable pursuant to outstanding performance shares. In addition, as of February 22, 2019, warrants to purchase up to 3,528,027 shares of our common stock were outstanding and immediately exercisable. Shares issued upon exercise of these warrants will generally be freely transferable without restriction or registration under the Securities Act pursuant to Section 1145 of the Bankruptcy Code.
A large percentage of our shares of common stock are held by a relatively small number of investors. We entered into a registration rights agreement (the “Registration Rights Agreement”) with certain of those investors in connection with our emergence from the Chapter 11 Proceeding pursuant to which we have filed a registration statement with the SEC to facilitate potential future sales of such shares by them. In addition, we filed a registration statement with the SEC following the closing of the O-Tex Transaction to register for sale the shares of Specified C&J Common Stock issued to the Stockholders pursuant to the Merger Agreement. Sales of a substantial number of shares of our common stock in the public markets, or even the perception that these sales might occur, could impair our ability to raise capital through a future sale of, or pay for acquisitions using, our equity securities.
We may issue shares of our common stock or other securities from time to time as consideration for future acquisitions and investments. If any such acquisition or investment is significant, the number of shares of our common stock, or the number or aggregate principal amount, as the case may be, of other securities that we may issue may in turn be substantial. We may also grant registration rights covering those shares of our common stock or other securities in connection with any such acquisitions and investments.
We cannot predict the effect that future sales of our common stock will have on the price at which our common stock trades or the size of future issuances of our common stock or the effect, if any, that future issuances will have on the market price of our common stock. Sales of substantial amounts of our common stock, or the perception that such sales could occur, may adversely affect the trading price of our common stock.
We have outstanding warrants that are exercisable for shares of common stock of the Company. The exercise of such equity instruments would have a dilutive effect to stockholders of the Company.
On January 6, 2017, we issued 1,180,083 warrants that are exercisable into shares of common stock of the Company at an initial exercise price of $27.95 per warrant. In addition, on July 26, 2017, we issued an additional 2,360,166 warrants with the same terms pursuant to the Warrant Agreement. The exercise of these warrants into common stock would have a dilutive effect to the holdings of our existing stockholders. As of February 22, 2019, warrants to purchase up to 3,528,027 shares of our common stock were outstanding and immediately exercisable. Shares issued upon exercise of these warrants will generally be freely transferable without restriction or registration under the Securities Act pursuant to Section 1145 of the Bankruptcy Code. The warrants will not expire until January 6, 2024 and may create an overhang on the market for, and have a negative effect on the market price of, our common stock.
There is no guarantee that outstanding warrants will continue to be in the money, and unexercised warrants may expire worthless. Further, the terms of such warrants may be amended.
If our stock price is below $27.95 per share, the warrants will have limited economic value, and they may expire worthless. In addition, the warrant agreement provides that the terms of the warrants may be amended without the consent of any holder to cure any ambiguity or correct any defective provision but requires the approval by the holders of at least a certain percentage of the then-outstanding warrants originally issued to make any change that adversely affects the interests of the holders. Accordingly, we may amend the terms of the warrants in a manner adverse to a holder if holders of at least a certain percentage of the then outstanding warrants approve of such amendment.
Because we currently have no plans to pay regular dividends on our common stock for the foreseeable future, you may not receive any return on your investment unless you sell your common stock for a price greater than that which you paid for it.
We have no plans to pay regular dividends on our common stock. Any declaration and payment of future dividends to holders of our common stock is limited by restrictive covenants in our Credit Facility and will be at the sole discretion of our Board and will depend on many factors, including our financial condition, earnings, capital requirements, level of indebtedness, cash flows, statutory and contractual restrictions applying to the payment of dividends and other considerations that our Board deems relevant. In addition, any agreements governing our future indebtedness may restrict our ability to pay dividends on our common stock. As a result, you may not receive any return on your investment unless you sell your common stock for a price greater than that which you paid for it.
Certain provisions of our Certificate of Incorporation, Bylaws, Stockholders Agreement and our stockholder rights plan may make it difficult for stockholders to change the composition of our Board and may discourage, delay or prevent a merger or acquisition that some stockholders may consider beneficial.
Certain provisions of our Certificate of Incorporation and our Bylaws may have the effect of delaying or preventing changes in control if our Board determines that such changes in control are not in the best interests of the Company and our stockholders. The provisions in our Certificate of Incorporation and our Bylaws include, among other things, those that:
•
classify the Board;
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limit removal of directors;
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authorize our Board to issue preferred stock and to determine the price and other terms, including preferences and voting rights, of those shares without stockholder approval;
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establish advance notice procedures for nominating directors or presenting matters at stockholder meetings;
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prohibit cumulative voting;
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prohibit action by written consent; and
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provide that only the Board may call special meetings of stockholders.
These provisions may prevent or discourage attempts to remove and replace incumbent directors. These provisions may also 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, which is responsible for appointing the members of our management.
We may issue preferred stock on terms that could adversely affect the voting power or value of our common stock.
Our Certificate of Incorporation authorizes our Board 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 the Board may determine. The terms of one or more classes or series of preferred stock could adversely affect 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 directors in all events or on the happening of specified events or the right to veto specified transactions. Similarly, the repurchase or redemption rights or liquidation preferences we might assign to holders of preferred stock could affect the residual value of the common stock.
Item 1B.
Item 1B. Unresolved Staff Comments
None.
Item 2.
Item 2. Properties
We lease office space for our principal executive headquarters, which is located at 3990 Rogerdale Rd., Houston, Texas 77042, and for our research and technology facility at 10771 Westpark Dr., Houston, Texas 77042. We also own property for our maintenance facility at 1214 Gas Plant Rd., San Angelo, Texas 76904. In addition, we own or lease numerous other smaller facilities and administrative offices across the geographic regions in which we operate to support our ongoing operations, including district offices, local sales offices, yard facilities and temporary facilities to house employees in regions where infrastructure is limited. We do not believe that any one of these facilities is individually material to our operations. Our leased properties are subject to various lease terms and expirations.
We believe all properties that we currently occupy are suitable for their intended uses. We believe that our current facilities are sufficient to conduct our operations. However, we continue to evaluate the purchase or lease of additional properties or the consolidation of our properties, as our business requires.
Item 3.
Item 3. Legal Proceedings
We are subject to various legal proceedings and claims incidental to or arising in the ordinary course of our business. Our management does not expect the outcome in any of these known legal proceedings, individually or collectively, to have a material adverse effect on our consolidated financial condition or results of operations.
U.S. Department of Justice Criminal Investigation into Pre-Nabors Merger Incident
There is a pending criminal investigation led by the Department of Justice in connection with a fatality that occurred at a facility we now own in Williston, North Dakota. The fatality occurred on October 3, 2014, prior to our acquisition of such facility and the ongoing business in connection with the Nabors Merger. We are cooperating fully with the investigation and expect to continue to do so. At this time, we cannot predict the outcome of the investigation.
Item 4.
Item 4. Mine Safety Disclosures
Not applicable.
PART II
Item 5.
Item 5. Market for Registrant’s Common Equity and Related Stockholder Matters and Issuer Purchases of Equity Securities
Market Price of and Dividends on the Registrant’s Common Equity and Related Stockholder Matters
Our common stock is traded on the NYSE under the symbol “CJ.” As of February 22, 2019, we had 66,062,430 shares of common stock issued and outstanding, held by approximately 12 registered holders. The number of registered holders does not include holders that have common stock held for them in “street name,” meaning that the stock is held for their accounts by a broker or other nominee. In these instances, the brokers or other nominees are included in the number of registered holders, but the underlying holders of the common stock that hold such stock in “street name” are not.
On February 22, 2019, the last reported sales price of our common stock on the NYSE was $17.62 per share.
We have not declared or paid any cash dividends on our common stock, and we do not anticipate declaring or paying any cash dividends to holders of our common stock in the foreseeable future. Payments of dividends, if any, will be at the discretion of our Board and will depend on our results of operations, financial condition, capital requirements and other factors deemed relevant by our Board. Additionally, covenants contained in our Credit Facility restrict the payment of cash dividends on our common stock. Please read Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations-Liquidity and Capital Resources-Description of our Credit Agreement” in this Annual Report.
Recent Sales of Unregistered Securities
No equity securities of the Company were sold during the period covered by this report that were not registered under the Securities Act.
Purchases of Equity Securities by the Issuer and Affiliated Purchasers
Repurchases of Equity Securities
The following table summarizes stock repurchase activity for the three months ended December 31, 2018 (in thousands, except average price paid per share).
(a) On July 31, 2018, the Company’s Board of Directors approved a stock repurchase program authorizing the repurchase of up to $150.0 million of the Company’s common stock, inclusive of commissions, over a twelve month period starting August 1, 2018. Repurchases may commence or be suspended at any time without notice. The program does not obligate the Company to purchase a specified number of shares of common stock during the period or at all, and may be modified or suspended at any time at the Company’s discretion. No assurance can be given that shares will be repurchased in the future.
(b) Represents shares that were withheld by us to satisfy tax withholding obligations of employees that arose upon the vesting of restricted shares. The value of such shares is based on the closing price of our common shares on the vesting date.
(c) Includes 45,278 shares that were withheld by us to satisfy tax withholding obligations of employees that arose upon the vesting of restricted shares. The value of such shares is based on the closing price of our common shares on the vesting date.
Item 6.
Item 6. Selected Financial Data
This section presents our selected consolidated financial data for the periods and as of the dates indicated. The selected historical consolidated financial data presented below is not intended to replace our historical consolidated financial statements. The following selected consolidated financial data should be read in conjunction with both Part II, 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 is intended to assist you in understanding our business and results of operations together with our present financial condition. This section should be read in conjunction with the audited consolidated financial statements and the related notes thereto included elsewhere in this Annual Report. This discussion and analysis contains forward-looking statements that involve risks and uncertainties. Our actual results may differ materially from those discussed in any forward-looking statement because of various factors, including, without limitation, those described in the sections titled “Cautionary Note Regarding Forward-Looking Statements” and Part I, Item 1A “Risk Factors” of this Annual Report.
Business Overview
C&J Energy Services, Inc., a Delaware corporation (the “Successor” and together with its consolidated subsidiaries for periods subsequent to the Plan Effective Date, “C&J” “we”, “our” or the “Company”) is a leading provider of well construction, intervention, completion, support and other complementary oilfield services and technologies. We provide our services to oil and gas exploration and production companies throughout the continental United States. We are a new well focused provider offering a diverse suite of services throughout the life cycle of the well, including hydraulic fracturing, cased-hole wireline and pumping, cementing, coiled tubing, rig services, fluids management and other completion and well support services. Based on internal estimates and publicly available data, we believe we are a market leader across most of our service lines, and our goal is to be the top service provider and a market leader for the U.S. land markets across all of our service lines. We are headquartered in Houston, Texas and operate across all active onshore basins in the continental United States.
Demand for our services, and therefore our operating and financial performance, is heavily influenced by drilling, completion and production activity by our customers, which is significantly impacted by commodity prices. Due to a severe industry downturn, the Predecessor Companies voluntarily filed petitions for reorganization seeking relief under the provisions of Chapter 11 of the United States Bankruptcy Code in 2016. We emerged in 2017 from the Chapter 11 Proceeding as the market was beginning to recover. See Part I, Item 1 “Business” of this Annual Report for an overview of our history, including additional information on our predecessor's bankruptcy filing, and business environment.
Operating Overview & Strategy
Our revenues and profits are generated by providing services and equipment to customers who operate oil and gas properties and invest capital to drill new wells and enhance production or perform maintenance on existing wells. Our results of operations in our core service lines are driven primarily by five interrelated, fluctuating variables: (1) the drilling, completion and production activities of our customers, which is primarily driven by oil and natural gas prices and directly affects the demand for our services; (2) the price we are able to charge for our services and equipment, which is primarily driven by the level of demand for our services and the supply of equipment capacity in the market; (3) the cost of materials, supplies and labor involved in providing our services, and our ability to pass those costs on to our customers; (4) our activity, or “utilization” levels; and (5) the quality, safety and efficiency of our service execution.
Our operating strategy is focused on maintaining high asset utilization levels to maximize revenue generation while controlling costs to gain a competitive advantage and drive returns. We believe that the quality and efficiency of our service execution and aligning with customers who recognize the value that we provide through service quality and efficiency gains are central to our efforts to support utilization and grow our business. For additional information about how each of our business segments measure asset utilization, please see “Our Reportable Segments and Strategy” in Part I, Item 1 “Business.”
However, asset utilization cannot be relied on as wholly indicative of our financial or operating performance due to variations in revenue and profitability from job to job, the type of service to be performed and the equipment, personnel and consumables required for the job, as well as competitive factors and market conditions in the region in which the services are performed. Given the volatile and cyclical nature of activity drivers in the U.S. onshore oilfield services industry, coupled with the varying prices we are able to charge for our services and the cost of providing those services, among other factors, operating margins can fluctuate widely depending on supply and demand at a given point in the cycle.
Historically, our utilization levels have been highly correlated to U.S. onshore spending by our customers, which is heavily driven by the price of oil and natural gas. Generally, as capital spending by our customers increases, drilling, completion and production activity also increases, resulting in increased demand for our services, and therefore more days or hours worked (as the case may be). Conversely, when drilling, completion and production activity levels decline due to lower spending by our customers, we generally provide fewer services, which results in fewer days or hours worked (as the case may
be). Additionally, during periods of decreased spending by our customers, we may be required to discount our rates or provide other pricing concessions to remain competitive and support utilization, which negatively impacts our revenue and operating margins. During periods of pricing weakness for our services, we may not be able to reduce our costs accordingly, and our ability to achieve any cost reductions from our suppliers typically lags behind the decline in pricing for our services, which could further adversely affect our results. Furthermore, when demand for our services increases following a period of low demand, our ability to capitalize on such increased demand may be delayed while we reengage and redeploy equipment and crews that have been idled during a downturn. The mix of customers that we are working for, as well as our exposure to the spot market, also impacts our utilization. For additional information about factors impacting our business and results of operations, please see “Industry Trends and Outlook” in this Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
To help manage asset utilization and profitability in our operations, our management monitors revenue, Adjusted EBITDA by reportable segment and certain operational data indicative of utilization levels, which information is provided for each of our operating segments under “Reportable Segments” in this Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” Management evaluates the financial performance of our reportable segments primarily based on each segment's Adjusted EBITDA because management believes Adjusted EBITDA provides important information about the activity and profitability of our lines of business within each reportable segment and aids us in analytical comparisons for purposes of, among other things, efficiently allocating our assets and resources. Adjusted EBITDA at the segment level is not considered to be a non-GAAP financial measure as it is our segment measure of profit or loss and is required to be disclosed under GAAP pursuant to ASC 280. Please read Note 7 - Segment Information in Part II, Item 8 “Financial Statements” of this Annual Report, for the definition and calculation of Adjusted EBITDA.
Results of Operations
The following is a comparison of our results of operations for the year ended December 31, 2018, compared to the year ended December 31, 2017, and a comparison of our results of operations for the year ended December 31, 2017, compared to the year ended December 31, 2016. The results for the Predecessor on January 1, 2017 reflect solely the impact of the application of fresh start accounting on that date and are therefore not included in the discussion of results of operations below.
Results for the Year Ended December 31, 2018 Compared to the Year Ended December 31, 2017
The following table summarizes the change in our results of operations for the year ended December 31, 2018, compared to the year ended December 31, 2017:
Revenue
Revenue increased $583.4 million, or 35.6%, to $2.2 billion for the year ended December 31, 2018, as compared to $1.6 billion for the year ended December 31, 2017. The increase in revenue was primarily due to (i) an increase of $346.6 million of revenue in our Completion Services segment primarily as a result of our expanded fracturing services asset base, (ii) an increase of $226.2 million in our Well Construction and Intervention Services ("WC&I") segment primarily as a result of our expanded cementing business with the O-Tex Transaction during the fourth quarter of 2017 and (iii) an increase of $10.6 million in our Well Support Services segment primarily as a result of improving utilization and pricing levels, partially offset by the divestiture of our Canadian rig services business in the fourth quarter of 2017.
Direct Costs
Direct costs increased $436.6 million, or 33.9%, to $1.7 billion for the year ended December 31, 2018, as compared to $1.3 billion for the year ended December 31, 2017. The increase in direct costs was primarily due to the operations of our expanded asset bases and improved utilization which resulted in additional labor and consumable costs, as well as our expanded cementing business with the acquisition of O-Tex.
As a percentage of revenue, direct costs decreased to 77.6% for the year ended December 31, 2018, as compared to 78.6% for the year ended December 31, 2017. The decrease was primarily due to improved pricing for our services due to the more favorable market conditions as well as the divestiture of underperforming businesses and shutting down unprofitable districts.
Selling, General and Administrative Expenses ("SG&A") and Research and Development Expenses ("R&D")
SG&A decreased $25.4 million, or 10.1%, to $225.5 million for the year ended December 31, 2018, as compared to $250.9 million for the year ended December 31, 2017. The decrease in SG&A was primarily due to (i) an $11.2 million reduction in employee related costs (excluding O-Tex), (ii) a $10.8 million reduction in share-based compensation expense related to an accelerated vesting in the first quarter of 2017, (iii) a $7.9 million reduction in restructuring charges related to our Chapter 11 bankruptcy proceeding in the corresponding prior year period, (iv) a $3.6 million reduction in acquisition-related costs related to the O-Tex Transaction and (v) a $1.9 million reduction in legal expenses, offset by (i) an incremental $10.1 million increase in SG&A expenses as a result of the acquisition of O-Tex and (ii) a $4.2 million increase in severance expense and accelerated equity vesting associated with the departure of an executive officer.
Depreciation and Amortization Expense ("D&A")
D&A increased $84.2 million, or 59.9%, to $224.9 million for the year ended December 31, 2018, as compared to $140.7 million for the same period in 2017. The increase in D&A was primarily the result of increased capital expenditures associated with equipment placed into service during 2018 as well as the integration of the acquired O-Tex assets in the fourth quarter of 2017.
Impairment Expense
During the fourth quarter of 2018, a significant decline in our share price, which resulted in our market capitalization dropping below our book value of equity, as well as an overall decrease in commodity prices were deemed triggering events that led to a test for goodwill impairment. Based on the results of the test, we recorded impairment expense of $146.0 million for the year ended December 31, 2018, consisting of all of the goodwill associated with our WC&I reporting unit.
Gain (loss) on disposal of assets
Loss on disposal of assets increased $57.1 million, or 181.6% to $25.7 million for the year ended December 31, 2018, as compared to a gain of $31.5 million for the same period in 2017. The increase is primarily related to a charge of $21.4 million in 2018, in connection with the retirement of certain assets, primarily within the fracturing, coiled tubing and well support services asset groups, that were deemed to be obsolete with unfavorable economics for refurbishment based on prevailing customer preferences and current market conditions. During 2017, the $31.5 million gain on disposal of assets was primarily related to the sale of assets associated with our Canadian rig services business and the sale of our equipment manufacturing and repair business.
Income Taxes
We recorded an income tax benefit of $2.4 million for the year ended December 31, 2018, at an effective rate of 1.8%, compared to an income tax benefit of $39.8 million for the year ended December 31, 2017, at an effective rate of 229.8%. The decrease in the effective tax rate is primarily due to adjustments to maintain a full valuation allowance in 2018, compared with a partial release of valuation allowance in 2017, which provided the additional income tax benefit. In addition, in 2018, due to U.S. Tax Reform, we netted indefinite-lived deferred tax liabilities with certain indefinite-lived deferred tax assets, including net operating loss carryforwards generated after January 1, 2018 before applying the valuation allowance.
Results for the Year Ended December 31, 2017 Compared to the Year Ended December 31, 2016
The following table summarizes the change in our results of operations for the year ended December 31, 2017, compared to the year ended December 31, 2016 (in thousands):
Revenue
Revenue increased $667.6 million, or 68.7%, to $1.6 billion for the year ended December 31, 2017, as compared to $971.1 million for the year ended December 31, 2016. The increase in revenue was primarily due to (i) an increase of $591.1 million in our Completion Services segments a result of the continued strong demand for all of our completion services, which resulted in improved utilization and pricing across our asset base, (ii) an increase of $65.6 million in our WC&I Services segment primarily due to continued strong demand and utilization across our cementing and coiled tubing service lines and (iii) an increase of $18.5 million in our Well Support segment as a result of improvement in both our rig services and special services product lines, offset by a decrease of $7.6 million in our Other Services segment as a result of the segment being divested during the comparable prior year period.
Direct Costs
Direct costs increased $340.8 million, or 36.0%, to $1.3 billion for the year ended December 31, 2017, as compared to $947.3 million for the year ended December 31, 2016. The increase in direct costs was primarily due to the corresponding increase in revenue from our Completion and WC&I Services segments, which resulted in additional labor and consumable costs. Revenue has been positively impacted by overall increased utilization levels across our Completion Services, WC&I Services and Well Support Services segments which resulted from the improved market environment.
As a percentage of revenue, direct costs decreased to 78.6% for the year ended December 31, 2017, as compared to 97.5% for the year ended December 31, 2016. The decrease was primarily due to substantially improved pricing for our services due to the more favorable market conditions resulting from the increase in commodity prices.
Selling, General and Administrative Expenses ("SG&A") and Research and Development Expenses ("R&D")
SG&A increased $21.6 million, or 9.4%, to $250.9 million for the year ended December 31, 2017, as compared to $229.3 million for the year ended December 31, 2016. The increase in SG&A was primarily due to (i) a $40.8 million increase in compensation expense primarily as a result of (a) significant increases in operating performance throughout 2017 and (b) the reinstatement of certain previously reduced compensation programs during the first half of 2017, (ii) a $10.3 million increase in professional fee expense primarily as a result of efficiency initiatives within our finance and human resources departments and (iii) a $3.8 million increase in acquisition-related costs related to the O-Tex acquisition, partially offset by (i) a $19.2 million reduction in costs related to our restructuring activities and Chapter 11 Proceeding during the corresponding prior year period, (ii) a $9.2 million reduction in integration related costs incurred in the corresponding prior year primarily related to the planned implementation of the new ERP system and (iii) a $6.1 million reduction in severance costs as a result of headcount reductions in the corresponding prior year period.
Depreciation and Amortization Expense ("D&A")
D&A decreased $76.8 million, or 35.3%, to $140.7 million for the year ended December 31, 2017, as compared to $217.4 million for the same period in 2016. The decrease in D&A was primarily due to a lower value of the asset base as a result of the estimated fresh start adjustments on the Fresh Start Reporting Date to our property, plant and equipment ("PP&E") and other intangible assets.
Impairment Expense
Due to the severe downturn in the oil and gas industry, and the resulting weakness in demand for our services, we determined that it was necessary to test goodwill for impairment and to test PP&E and other intangible assets for recoverability throughout 2016.
Impairment expense for the year ended December 31, 2016 was $436.4 million, consisting of $314.3 million of goodwill impairment related to impairment of all remaining goodwill associated with our Well Support Services segment, along with $61.0 million related to other intangible assets and $61.1 million related to PP&E within each of our Completion Services, Well Support Services, and Other Services segments.
Gain (loss) on disposal of assets
Gain on disposal of assets increased $34.5 million to $31.5 million for the year ended December 31, 2017, as compared to a loss of $3.1 million for the same period in 2016. The increase is related to a $31.5 million gain on disposal of
assets during 2017, which was primarily related to the sale of assets associated with its Canadian rig services business and its divested equipment manufacturing and repair business.
Reorganization items
Reorganization items of $55.3 million for the year ended December 31, 2016 are primarily related to professional fees of $41.2 million, contract termination settlements of $20.3 million and revisions of estimated claims of $0.8 million, partially offset by $5.2 million in related party settlements and $1.8 million in vendor claims adjustments in connection with our Chapter 11 Proceeding.
Interest Expense, net
Interest expense decreased $155.9 million, or 99.0%, to $1.5 million for the year ended December 31, 2017 from $157.5 million for the year ended December 31, 2016. The decrease is primarily due to the settlement of all outstanding borrowings of the Predecessor in accordance with the Restructuring Plan in addition to the prior year $91.9 million of accelerated amortization of original issue discount and deferred financing costs as a result of the Restructuring Support agreement.
Income Taxes
We recorded an income tax benefit of $39.8 million for the year ended December 31, 2017, at an effective rate of 229.8%, compared to income tax benefit of $129.0 million for the year ended December 31, 2016, at an effective rate of 12.0%. The increase in the effective tax rate is primarily due to adjustments to reduce valuation allowances previously applied against certain deferred tax assets, including net operating loss carryforwards. These adjustments were the result of the treatment of the O-Tex Transaction as a non-taxable transaction, resulting in the acquired assets and liabilities having carryover basis for tax purposes. At the closing of the transaction, an estimated deferred tax liability of approximately $31.3 million was recorded to account for the differences between the preliminary purchase price allocation and carryover tax basis.
Our Reportable Segments
As of December 31, 2018, our reportable segments were:
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Completion Services, which consists of the following businesses and service lines: (1) fracturing services; (2) cased-hole wireline and pumping services; and (3) completion support services, which includes our R&T department.
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Well Construction and Intervention Services, which consists of the following businesses and service lines: (1) cementing services and (2) coiled tubing services.
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Well Support Services, which consists of the following businesses and service lines: (1) rig services; (2) fluids management services; and (3) other specialty well site services.
During the first quarter of 2018, we decided to exit our directional drilling business and artificial lift business. We are in the process of divesting the assets and inventory associated with our directional drilling operations. We completed the sale of substantially all of the assets and inventory associated with the artificial lift business on July 2, 2018.
Our reportable segments are described in more detail below; for financial information about our reportable segments, including revenue from external customers and total assets by reportable segment, please see “Note 11 - Segment Information” in Part II, Item 8 “Financial Statements and Supplementary Data” of this Annual Report.
Completion Services
The core services provided through our Completion Services segment are fracturing, cased-hole wireline and pumping services. Our completion support services are focused on supporting the efficiency, reliability and quality of our operations. Our R&T department provides in-house manufacturing capabilities that help to reduce operating cost and enable us to offer more technologically advanced and efficiency focused completion services, which we believe is a competitive differentiator. For example, through our R&T department we manufacture the data control instruments used in our fracturing operations and the perforating guns and addressable switches used in our wireline operations; these products are also available for sale to third-parties. The majority of revenue for this segment is generated by our fracturing business.
During the fourth quarter of 2018, our fracturing business deployed, on average, approximately 650,000 hydraulic horsepower (“HHP”) out of our fleet of approximately 860,000 HHP as of December 31, 2018. We exited the year with approximately 695,000 HHP deployed, consisting of sixteen horizontal and two vertical fleets. Our typical horizontal fleet size consists of 20 pumps, or approximately 40,000 HHP, and our typical vertical fleet size consists of 10 pumps, or approximately 20,000 HHP. In our cased-hole wireline and pumping business, during the fourth quarter of 2018, we deployed, on average, approximately 70 wireline trucks and 81 pumpdown units. Not all of our deployed assets are utilized fully, or at all, at any given time, due to, among other things, routine scheduled maintenance and downtime.
Revenue and profitability for the fourth quarter of 2018 decreased year-over-year and sequentially in our Completion Services segment due to customer budget exhaustion and lower utilization levels. Due to soft market conditions, we temporarily idled two horizontal equivalent fleets early in the fourth quarter. We focused on reallocating fleets on a dedicated basis to large, efficient customers and these two fleets were re-deployed to dedicated customers in early December, and we exited the fourth quarter at our third quarter exit rate of 695,000 HHP deployed. In our wireline and pumping businesses, lower customer activity levels from budget exhaustion, year-end seasonality and weather-driven delays resulted in both revenue and profitability for the fourth quarter of 2018 decreasing year-over-year and sequentially.
For the year ended December 31, 2018, revenue from our Completion Services segment was $1.5 billion, representing approximately 65.4% of our total revenue, compared with revenue of $1.1 billion for the year ended December 31, 2017, which represents a 31.3% year-over-year increase. Adjusted EBITDA from this segment for the year ended December 31, 2018 was $274.3 million, compared with $200.9 million of Adjusted EBITDA for the year ended December 31, 2017, which represents a 36.5% year-over-year increase.
Please see Note 11 - Segment Information” in Part II, Item 8 “Financial Statements and Supplementary Data” of this Annual Report, for the definition and calculation of Adjusted EBITDA.
Well Construction and Intervention Services
The core services provided through our Well Construction and Intervention Services segment are cementing and coiled tubing services. Although we previously provided directional drilling services through this segment, we ceased those operations during the first quarter of 2018, and we are in the process of selling the related assets and inventory. The majority of revenue for this segment is generated by our cementing business. During the fourth quarter of 2018, our cementing business deployed, on average, approximately 69 cementing units and in our coiled tubing business, we deployed, on average, approximately 17 coiled tubing units during the quarter. Our deployed assets may not be utilized fully, or at all, at any given time, due to, among other things, routine scheduled maintenance and downtime.
The deployment of additional assets and the acquisition of O-Tex caused both fourth quarter revenue and profitability in our Well Construction and Intervention Services segment to increase year-over-year; however, fourth quarter revenue and profitability decreased sequentially mostly due to customer budget exhaustion and year-end seasonality. These
conditions particularly impacted our cementing business, and we experienced unexpected customer shutdowns. On average, all of our large diameter coiled tubing units were deployed throughout the quarter, but overall activity levels decreased due to higher levels of year-end seasonality and an unfavorable job mix as completion-driven activity levels slowed at year-end.
For the year ended December 31, 2018, revenue from our Well Construction and Intervention Services segment was $375.7 million, representing approximately 16.9% of our total revenue, compared with revenue of $149.5 million for the year ended December 31, 2017, which represents a 151.3% year-over-year increase. Adjusted EBITDA from this segment for the year ended December 31, 2018 was $68.5 million, compared with $21.0 million of Adjusted EBITDA for the year ended December 31, 2017, which represents a 226.7% year-over-year increase.
Please read Note 11 - Segment Information” in Part II, Item 8 “Financial Statements and Supplementary Data” of this Annual Report, for additional information about segment Adjusted EBITDA.
Well Support Services
Our Well Support Services segment focuses on post-completion activities at the well site, including rig services, such as workover and plug and abandonment, fluids management services, and other specialty well site services. Although we previously provided artificial lift applications through this segment, we completed the sale of substantially all of the assets and inventory associated with this business on July 2, 2018. Additionally, in 2017 and 2018 in response to the highly competitive landscape and reflecting our returns-focused strategy, we have continued to focus on operational rightsizing measures to better align these businesses with current market conditions. This strategy has resulted in closing facilities and idling unproductive equipment. For example, we divested our Canadian rig services business during the fourth quarter of 2017, we exited the condensate hauling business in South Texas during the first quarter of 2018, and we shut-down our East Texas rig services operations late in the second quarter of 2018. The majority of revenue for this segment is generated by our rig services business, and we consider rig services and fluids management to be the core businesses within this segment.
During the fourth quarter of 2018, our rig services business deployed, on average, approximately 123 workover rigs per workday out of our average fleet of approximately 344 marketable workover rigs. In our fluids management business, we deployed, on average, approximately 645 fluid services trucks per workday and approximately 1,403 frac tanks per workday. In our fluids management business, we own 23 private salt water disposal wells for fluids disposal purposes. However, our deployed assets may not be utilized fully, or at all, at any given time, due to, among other things, routine scheduled maintenance and downtime.
Segment revenue and profitability for the fourth quarter increased both year-over-year and sequentially due to the deployment of additional assets in the U.S. and higher overall pricing for our services. The prior year period contained partial results from our Canadian rig services business that we divested in early November 2017, which diluted the 2018 year-over-year operating results improvement. In our rig services business, we deployed additional workover rigs into our core operating basins of California and West Texas, and we exited the fourth quarter with our highest deployed workover rig count of 2018. These improved results were partially offset by higher levels of year-end seasonality and select unexpected customer shutdowns in several of our core operating basins, especially in the Bakken and the Rocky Mountain regions. Special services revenue and profitability remained strong primarily due to increased fishing and rental activity in select basins. Our fluids management business benefited from the full implementation of several contract wins in the third quarter of 2018 for California operations,
which was partially offset by lower activity levels in South Texas due to unexpected downtime at certain saltwater disposal wells.
For the year ended December 31, 2018, revenue from our Well Support Services segment was $392.8 million, representing approximately 17.7% of our total revenue, compared with revenue of $382.2 million for the year ended December 31, 2017, which represents a 2.8% year-over-year increase. Adjusted EBITDA from this segment for the year ended December 31, 2018 was $39.7 million, compared with $9.2 million of Adjusted EBITDA for the year ended December 31, 2017, which represents a 329.8% year-over-year increase.
Please read Note 11 - Segment Information” in Part II, Item 8 “Financial Statements and Supplementary Data” of this Annual Report, for additional information about segment Adjusted EBITDA.
Industry Trends and Outlook
We face many challenges and risks in the industry in which we operate. Although many factors contributing to these risks are beyond our ability to control, we continuously monitor these risks and have taken steps to mitigate them to the extent practicable. In addition, while we believe that we are well positioned to capitalize on available growth opportunities, we may not be able to achieve our business objectives and, consequently, our results of operations may be adversely affected. Please read the factors described in the sections titled “Cautionary Note Regarding Forward-Looking Statements” and “Risk Factors” in Part I, Item 1A of this Annual Report for additional information about the known material risks that we face.
General Industry Trends
The oil and gas industry has traditionally been volatile and is influenced by a combination of long-term, short-term and cyclical trends, including domestic and international supply and demand for oil and gas, current and expected future prices for oil and gas and the perceived stability and sustainability of those prices, production depletion rates and the resultant levels of cash flows generated and allocated by oil and gas companies to their drilling, completion and workover budgets. The oil and gas industry is also impacted by geopolitical factors, such as general domestic and international economic conditions, the actions of the OPEC oil cartel, political instability in oil producing countries, government regulations (both in the United States and elsewhere), levels of consumer demand, the availability of pipeline capacity, weather conditions in the U.S., and other factors that are beyond our control.
Demand for our services tends to be volatile because it is a direct function of our customers’ willingness to make operating and capital expenditures to explore for, develop and produce hydrocarbons in the United States. Our customers’ willingness to undertake such activities and make such expenditures depends largely upon prevailing industry conditions, which are influenced by numerous factors that are beyond our control, including, among others, those described above. The current and projected prices of oil, natural gas and natural gas liquids are important catalysts for customer activity levels. Perceived instability or weakness in oil and natural gas prices influences our customers to pause activity, curtail their operations, reduce their expenditures, and request pricing concessions to reduce their operating costs. In a lower oil and gas
price environment, demand for service and maintenance generally decreases as oil and gas producers decrease their activity and operating and capital expenditures. Because the type of services that we offer can be easily “started” and “stopped,” and oil and gas producers generally tend to be less risk tolerant 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. Given the significant influence of oil and gas prices, customer activity levels historically have been, and are expected to continue to be, highly volatile. A prolonged low level of customer activity could adversely affect our financial condition and results of operations.
Competition and Demand for Our Services
Our revenue and profitability are directly affected by changes in utilization and pricing levels for our services, which fluctuate in direct response to changes in the level of drilling, completion and production activity by our customers. Declines in utilization or pricing for our services impact, among other things, our ability to maintain revenue and profitability. During periods of declining pricing for our services, we may not be able to reduce our costs accordingly, which could further adversely affect our results. Furthermore, even when we are able to increase our prices, we may not be able to do so at a rate that is sufficient to offset any rising costs. In an unfavorable pricing environment, we may decide to idle equipment rather than work at unsustainable pricing levels, although we may not be able to fully reduce our costs accordingly. 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 position and results of operations.
We operate in highly competitive areas of the oilfield services industry with significant potential for excess capacity. With respect to all of our core services, the equipment can be moved with relative ease from one region to another in response to changes in customer activities and market conditions, which can result in an oversupply of equipment in high activity areas. Increases in supply relative to demand in our core operating areas and geographic markets could negatively impacted both pricing and utilization for our services and adversely affected our financial results.
See Part I, Item 1 “Business” for additional discussion of the market challenges within our industry.
Current Market Conditions and Outlook
The steady increase in oil prices from July 2017 through early October 2018 created a strong environment that incentivized our customers to increase their drilling and completion programs. During that time period, the price of oil averaged approximately $61.00 per barrel, a level that allowed many of our customers to generate adequate financial returns and incentivized them to increase drilling, completion and production activities in many domestic oil-producing basins. During that time period, the price of natural gas averaged $2.88 per Mcf, a level that has not encouraged a material increase in drilling and completion activities in natural gas focused basins. Our results for 2018 generally reflect our focus on large, efficient customers that have increased activity levels in the most prolific oil-producing basins in the Continental United States.
During the fourth quarter of 2018, the industry continued to experience concerns that growing oil production in West Texas may temporarily exceed the capacity of the region’s pipelines to transport oil from oil wells to oil refineries. We have a significant operating presence in West Texas and our financial results for the fourth quarter of 2018 were negatively impacted by lower activity levels in that basin. Additionally, many of our customers spent more than half of their capital expenditure budget in the first half of 2018, which resulted in higher levels of year-end budget exhaustion that negatively affected most of our businesses in almost all of our operating basins. Also, oil prices declined approximately 40% from a high of just over $76.00 per barrel in early October 2018 to a low of just under $43.00 per barrel in late December 2018, which contributed to higher levels of year-end seasonality and incentivized customers to delay planned expenditure into 2019. The timing of this oil price decline comes as many of our customer are formulating their 2019 capital spending plans, which we expect will have negative implications on activity levels and utilization of deployed equipment in 2019, especially in our new-well completion-oriented businesses.
We continue to monitor the market for our services and the competitive environment. Although the U.S. domestic rig count has increased off the historical low recorded in mid-2016, there are signs the drilling rig count could decline in early 2019 due to weakening oil prices and declining E&P capital expenditures. Additionally, increasing competition, logistical constraints and other factors, such as an oversupply of available equipment and lower overall pricing for our services, represent risks to our near-term financial results and may negatively impact our performance in many of our core businesses in 2019.
We will continue to manage our business in line with demand for our services and make adjustments as necessary to effectively respond to changes in market conditions, customer activity levels, pricing for our services and equipment, and utilization of our equipment and personnel. Our response to the industry's persistent uncertainty is to maintain sufficient
liquidity, preserve our conservative capital structure and closely monitor our discretionary spending. We take a measured approach to asset deployment, balancing our view of current and expected customer activity levels with a focus on generating positive returns for our shareholders. Our priorities remain to drive revenue by maximizing utilization, to improve margins through cost controls, to protect and grow our market share by focusing on the quality, safety and efficiency of our service execution, and to ensure that we are strategically positioned to capitalize on constructive market dynamics.
Completion Services Outlook
Our strategy of increasing our dedicated fleet count to large, existing customers should result in higher utilization and better financial performance in our fracturing business during the first quarter of 2019. Additionally, our spot horizontal fleet count has decreased back to lows not seen since the second quarter of 2018, and it is possible that we could have all of our deployed horizontal fleets dedicated by the end of the first quarter of 2019. With that said, the current market conditions remain volatile, and our primary focus remains to lower our overall cost structure and to more closely align with large, dedicated customers with deep inventories of work and proven track records of efficient operations, many of which we have created long-term relationships with over the past several years. In our wireline and pumping businesses, we expect a slow start to the first quarter as many of our customers in the Bakken and the Rocky Mountain regions have indicated they will not commence completion activities until the back half of the first quarter mostly due to inclement weather. We currently expect higher activity levels off year-end seasonal lows in many of our other operating regions such as West Texas and the Mid-Continent, but the expected slow start in the Northwest will offset financial improvement in our other operating basins during the first quarter of 2019.
Well Construction and Intervention Services Outlook
We currently expect that our Well Construction and Intervention Services segment will experience lower activity levels in the first quarter of 2019 primarily due to decreased completion activity and lower overall drilling rig count. Volatile market conditions and select customers releasing drilling rigs will most likely negatively impact our cementing business in the first quarter of 2019. With that said, we will remain focused on controlling costs, maintaining market share and high-grading our customer base by redeploying cementing units with existing customers that plan to maintain stable drilling rig counts in 2019. Despite strong customer demand and improving utilization in West Texas, we believe activity levels will decrease in our coiled tubing business in the first quarter of 2019 primarily due to unfavorable job mix from sluggish improvement in completion-driven activity in both South Texas and the Mid-Continent.
Well Support Services Outlook
We expect improvement in both revenue and profitability in our Well Support Services segment as we continue to benefit from higher activity levels and improved pricing from agreements implemented in late 2018. Additionally, we will continue to focus on deploying more assets with select customers in several of our core operating basins. Increased demand for workover and well maintenance activities should result in higher activity levels throughout the first quarter of 2019, excluding the potential negative impact from inclement weather that typically affects our Well Support Services segment in the first quarter. In our rig services business, we are focused on increasing profitable market share primarily in both California and West Texas due to our reputation of delivering superior service quality and safety and our ability to continue deploying upgraded, high-spec workover rigs. We have upgraded approximately forty-two high-spec workover rigs to date with fifteen of those delivered to customers in 2018, and we plan to deliver another eleven rigs to select customers in 2019. In our fluids management business, we plan to continue focusing on areas with improving fluids logistics and disposal demand, but potential growth opportunities will primarily be dependent upon asset availability and the easing of current labor constraints. Going forward, we will continue to focus on meeting improved customer demand and maintaining our strategy of aligning with customers who have deep inventories of work and who value our ability to safely deliver superior service quality, which should continue to result in increasing segment profitability and returns. That said, we are also exploring potential strategic opportunities for the Well Support Services business that would enable us to focus on growing our new well focused business.
Please see “Liquidity and Capital Resources” in this Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” in addition to “Cautionary Note Regarding Forward-Looking Statements” and “Risk Factors” in Part I, Item 1A of this Annual Report.
Regulations
The discussion set forth under Item 1. "Business - Government Regulations and Environmental, Health and Safety Matters" in our 2017 Annual Report is incorporated herein by reference.
On March 8, 2018, the President issued two Proclamations directing the imposition, effective March 23, 2018, of ad valorem tariffs of 25% on certain imported steel products and 10% on certain imported aluminum products from all countries, with the exception of Canada and Mexico. Subsequently, on March 22, 2018, the President issued two additional Proclamations that exempted, in addition to Canada and Mexico, several additional countries from the remedial tariff measures, as follows: (i) Argentina; (ii) Australia; (iii) Brazil; (iv) the 28 member countries of the European Union; and (v) South Korea. In Proclamations issued on April 30, 2018, the President: (i) permanently exempted South Korea from the imposition of tariffs on imported steel, while allowing tariffs to be imposed on imported aluminum; (ii) extended the steel and aluminum tariff exemptions for Argentina, Australia, and Brazil indefinitely to allow for continued negotiations; and (iii) extended the steel and aluminum tariff exemptions for Canada, Mexico, and the 28 member countries of the European Union to allow for continued negotiations, but only through May 31, 2018. In addition to possible country-based exemptions, the United States has established a protocol whereby individuals or entities using any of the affected steel or aluminum products in business activities, such as manufacturing, may request the exclusion of individual products from the imposition of tariffs. On May 31, 2018, the U.S. announced that it would also impose steel and aluminum tariffs on Canada, Mexico, and the 28 member countries of the European Union. In addition, Argentina, Australia, Brazil, and South Korea implemented measures to address the impairment to U.S. national security attributable to steel and aluminum imports that were deemed satisfactory to the United States. As a result, imports of steel and/or aluminum from these countries have been exempted from the imposition of tariff-based remedies, but, with the exception of Australia, the United States has implemented quantitative restrictions in the form of absolute quotas, meaning that imports in excess of the allotted quota will be disallowed.
Our R&T department is primarily engaged in the engineering and production of certain parts and components, such as perforating guns and addressable switches, which are used in the completion process. Certain of these items, particularly perforating guns used in our wireline operations, are manufactured using imported steel tubing, which is subject to a 25% tariff. We expect that, depending on the ultimate outcome of the country exemption and product exclusion processes described above, our raw material costs will increase and result in corresponding increases in the price of our finished goods. Further, in addition to the products manufactured by our R&T department, we expect that the costs of other high steel content products used in conjunction with our fracturing and coiled tubing operations, specifically power ends, fluid ends, treating iron and coiled tubing strings, will also increase as we expect the manufacturers of such goods to pass along the net effect the tariffs have on the cost of manufacturing such goods.
Liquidity and Capital Resources
Sources of Liquidity and Capital Resources
Our primary sources of liquidity have historically included, and we have funded our capital expenditures with, cash flows from operations, proceeds from public offerings of our common stock and borrowings under debt facilities. Our ability to generate future cash flows is subject to a number of variables, many of which are outside of our control, including the drilling, completion and production activity by our customers, which is highly dependent on oil and gas prices. See Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Industry Trends and Outlook” for additional discussion of certain factors that impact our results and the market challenges within our industry. See “-Financial Condition and Cash Flows” below for information about net cash provided by or used in our operating, investing and financing activities.
We have maintained a strong balance sheet and a conservative capital structure. As of December 31, 2018, we had a cash balance of $135.7 million and no borrowings drawn on our Credit Facility, which had $234.7 million of available borrowing capacity after taking into consideration outstanding letters of credit totaling $20.6 million. This resulted in total liquidity of $370.4 million as of December 31, 2018. As of February 22, 2019, we had a cash balance of approximately $84.9 million and no borrowings drawn on our Credit Facility, which had $234.7 million of available borrowing capacity after taking into consideration our current outstanding letters of credit totaling $20.6 million, resulting in total liquidity of approximately $319.6 million. Under the terms of our Credit Facility, the borrowing base is subject to monthly adjustments based on current levels of accounts receivable and inventory. For additional information about the Credit Facility, please see “Description of our Indebtedness” below and Note 3 - Debt in Part II, Item 8 “Financial Statements” of this Annual Report.
Our primary uses of cash are for operating costs, capital expenditures and other expenditures. The oilfield services business is capital-intensive, requiring significant investment to maintain, upgrade and purchase equipment to meet our customers’ needs and industry demand. Our capital expenditures consist primarily of:
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growth capital expenditures, which are capital expenditures made to acquire additional equipment and other assets, increase our service lines, or advance other strategic initiatives for the purpose of growing our business; and
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maintenance capital expenditures, which are capital expenditures related to our existing equipment, such as refurbishment and other activities to extend the useful life of partially or fully depreciated assets.
Capital expenditures totaled $311.1 million in 2018, primarily pertaining to the maintenance of deployed equipment, the refurbishment of previously stacked fracturing equipment and the building of new equipment for our Completion and Well Construction & Intervention Services segments. We decreased our 2018 capital expenditure budget in the second quarter from the initial estimated range of between $430.0 million and $450.0 million due to our decision to delay the refurbishment and future redeployment of three stacked horizontal frac fleets. We further decreased our capital expenditure budget in the third quarter due to less growth and maintenance capital spending in most of our core service lines as a result of lower activity levels and reduced customer demand.
On July 31, 2018, the Company's Board of Directors approved a stock repurchase program authorizing the repurchase, at the discretion of senior management, of up to $150.0 million of the Company’s common stock over the twelve month period starting August 1, 2018, in open market or in privately negotiated transactions, subject to U.S. Securities and Exchange Commission regulations, stock market conditions, capital needs of the business, and other factors. Repurchases may be commenced or suspended at any time without notice. In 2018, the Company executed the repurchase of approximately 2.4 million shares at an average cost of $16.55 per share.
We expect to fund our 2019 capital expenditure program primarily with cash flows from operations and potential borrowings under our Credit Facility. The amount of indebtedness we have outstanding at any time could limit our ability to finance future growth and could adversely affect our operations and financial condition. Based on our existing operating performance, we currently believe that our cash flows from operations, cash on hand and borrowings under our Credit Facility will be sufficient to meet our operational and capital expenditure requirements over the next twelve months.
Financial Condition and Cash Flows
The net cash provided by or used in our operating, investing and financing activities is summarized below:
Cash Provided by (Used in) Operating Activities
Net cash provided by operating activities was $342.1 million for the year ended December 31, 2018. The cash inflow was primarily from (i) adjustments for non-cash items of $416.2 million, (ii) $51.3 million of positive changes in other operating assets and liabilities primarily from the decrease of previous period investment in working capital, and (iii) $4.6 million related to state income and federal income tax refunds. This cash inflow was offset by a net loss of $130.0 million.
Net cash provided by operating activities was $0.1 million for the year ended December 31, 2017. The cash inflow was primarily related to net income of $22.5 million, adjustments for non-cash items of $106.4 million, cash provided from the collection of accounts receivable assumed in the O-Tex acquisition and positive changes in other operating assets and liabilities, excluding accounts receivable, inventory, accounts payable and accrued expenses. This cash inflow was offset by $149.3 million of (i) increased investment in working capital (accounts receivable, inventory, accounts payable and accrued expenses) as a result of the increase in the demand primarily for our completion service lines and the resulting increase in revenue and direct costs for the year ended December 31, 2017 and (ii) cash used to satisfy obligations related to accounts payable and accrued liabilities assumed in the O-Tex acquisition.
Net cash used in operating activities was $107.4 million for the year ended December 31, 2016. The use of cash was primarily related to a net loss of $944.3 million, offset by (i) adjustments for non-cash items of $713.5 million, (ii) cash
inflows of $101.3 million due to a decrease in our investment in working capital (accounts receivable, inventory, accounts payable and accrued expenses) as a result of the decrease in the demand for our services and the resulting decrease in revenue and direct costs during the year ended December 31, 2016, (iii) a decrease in the use of cash related to accounts payable and accrued expenses during the third and fourth quarters of 2016 both resulting from the automatic stay associated with the Chapter 11 Proceeding and (iv) positive changes in other operating assets and liabilities, excluding accounts receivable, inventory, accounts payable and accrued expenses.
Cash Flows Used in Investing Activities
Net cash used in investing activities was $276.2 million for the year ended December 31, 2018. The use of cash was related to $311.1 million of capital expenditures primarily pertaining to the maintenance of deployed equipment, the refurbishment of previously stacked equipment and related reactivation costs for equipment redeployed in both the second and third quarters of 2018, and the building of new equipment for our Completion and WC&I segments. These amounts were offset by (i) $33.4 million of proceeds from the disposal of property, plant and equipment and non-core service lines and (ii) a $1.5 million refund from a purchase price adjustment related to the O-Tex acquisition.
Net cash used in investing activities was $275.7 million for the year ended December 31, 2017. The use of cash was related to (i) $210.2 million of capital expenditures primarily pertaining to the refurbishment of stacked equipment and the construction of new-build frac pumps and refurbished ancillary equipment and (ii) $133.8 million related to the O-Tex Transaction. These amounts were offset by $68.3 million of proceeds from the divestiture of non-core business lines previously reported under our Other Services reportable segment and from the disposal of property plant and equipment.
Net cash used in investing activities was $26.9 million for the year ended December 31, 2016. The use of cash was related to $57.9 million of capital expenditures primarily pertaining to the new ERP system and to costs incurred to extend the useful lives of our existing equipment, offset by $32.8 million of proceeds from the disposal of property plant and equipment.
Cash Flows Provided by Financing Activities
Net cash used by financing activities was $44.4 million for the year ended December 31, 2018. The cash used was related to (i) $37.1 million for share repurchases in connection with our stock repurchase program, (ii) $3.9 million of settlement and employee tax withholding on restricted stock vestings and (iii) $3.5 million of cash paid for financing costs related to our Credit Facility.
Net cash provided by financing activities was $210.3 million for the year ended December 31, 2017. The cash provided was primarily from $215.9 million of proceeds from the public offering of common stock, partially offset by (i) $3.8 million of employee tax withholding on restricted stock vesting and (ii) $1.7 million of cash paid for financing costs related to our Credit Facility.
Net cash provided by financing activities was $174.3 million for the year ended December 31, 2016. The cash provided was primarily from (i) $174.0 million in proceeds from the Predecessor's revolving credit facility and (ii) $23.0 million in proceeds from the DIP Facility. These amounts were offset by (i) $13.3 million in payments on the Predecessor's revolving credit facility and term debt, (ii) $5.6 million for excess tax expense from share-based compensation, (iii) $2.4 million in payments related to capital lease obligations and (iv) $1.0 million of cash paid for financing costs related to our DIP Facility.
Description of our Indebtedness
Credit Facility
We and certain of our subsidiaries (the “Borrowers”) entered into an Asset-Based Revolving Credit Agreement with, among others, JPMorgan Chase Bank, N.A., as administrative agent (the “Agent”), on May 1, 2018 (the "Credit Facility"). The maturity date of the Credit Facility is May 1, 2023. The Credit Facility replaces the Prior Credit Facility, which was canceled and discharged on May 1, 2018. For additional information about the Prior Credit Facility, please see Note 3 - Debt in Part II, Item 8 “Financial Statements” of this Annual Report.
The Credit Facility allows the Borrowers to incur revolving loans in an aggregate amount up to the lesser of (a) $400.0 million or (b) a borrowing base (the “Loan Cap”), which borrowing base is based upon the value of the Borrowers’ accounts receivable, inventory and restricted cash, subject to eligibility criteria and customary reserves which may be modified in the Agent’s permitted discretion. The Credit Facility also provides for the issuance of letters of credit, which would further
reduce borrowing capacity thereunder. If at any time the amount of loans and other extensions of credit outstanding under the Credit Facility exceed the borrowing base, the Borrowers may be required, among other things, to prepay outstanding loans immediately.
The Borrowers’ obligations under the Credit Facility are secured by liens on a substantial portion of the Borrowers’ personal property, subject to certain exclusions and limitations. Upon the occurrence of certain events, additional collateral, including a portion of the Borrowers’ real properties, may also be required to be pledged. Each of the Borrowers is jointly and severally liable for the obligations of the other Borrowers under the Credit Facility.
At the Borrowers’ election, interest on borrowings under the Credit Facility will be determined by reference to either LIBOR plus an applicable margin of between 1.50% and 2.00% or an “alternate base rate” plus an applicable margin of between 0.50% and 1.00%, in each case based on the Company’s total leverage ratio. Interest will be payable quarterly for loans bearing interest based on the alternative base rate and on the last day of the interest period applicable to LIBOR-based loans and, in the case of an interest period longer than three months, quarterly, upon any prepayment and at final maturity. The Borrowers will also be required to pay a fee on the unused portion of the Credit Facility equal to (i) 0.50% per annum if average utilization is less than or equal to 25% or (ii) 0.375% per annum if average utilization is greater than 25%, in each case payable quarterly in arrears to the Agent.
The Credit Facility contains covenants that limit the Borrowers’ ability to incur additional indebtedness, grant liens, make loans, make acquisitions or investments, make distributions, merge into or consolidate with other persons, or engage in certain asset dispositions.
The Credit Facility also contains a financial covenant which requires us to maintain a monthly minimum fixed charge coverage ratio of 1.0:1.0 upon the occurrence of an event of default or on any date upon which the excess availability is less than the greater of (x) 12.5% of the Loan Cap and (y) $30.0 million. The fixed charge coverage ratio is generally defined in the Credit Facility as the ratio of (i) EBITDA minus certain capital expenditures and cash taxes paid to (ii) the sum of cash interest expenses, scheduled principal payments on borrowed money and certain distributions.
Contractual Obligations
The following table summarizes our contractual cash obligations as of December 31, 2018:
(1) Represents unused commitment fees on unused portion of the Credit Facility and outstanding letters of credit. As of December 31, 2018, there were no amounts outstanding under the Credit Facility.
Off-Balance Sheet Arrangements
We had no off-balance sheet arrangements, as defined in Item 303(a)(4)(ii) of Regulation S-K, as of December 31, 2018.
Critical Accounting Policies
The selection and application of accounting policies is an important process that has developed as our business activities have evolved and as the accounting standards have developed. Accounting standards generally do not involve a selection among alternatives, but involve the implementation and interpretation of existing standards, and the use of judgment applied to the specific set of circumstances existing in our business. We make every effort to properly comply with all applicable standards on or before their adoption, and we believe the proper implementation and consistent application of the accounting standards are critical.
Our discussion and analysis of our financial condition and results of operations is based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America (“U.S. GAAP”). The preparation of these consolidated financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, expenses and related disclosures. We base our estimates and assumptions on historical experience and on various other factors that we believe to be reasonable under the circumstances. We evaluate our estimates and assumptions on an ongoing basis. The results of our analysis form the basis for making assumptions about the carrying values of assets and liabilities that are not readily apparent from other sources. Our actual results may differ from these estimates under different assumptions or conditions.
We believe the following critical accounting policies involve significant areas of management’s judgments and estimates in the preparation of our consolidated financial statements.
Accounts Receivable and Allowance for Doubtful Accounts. Accounts receivable are generally stated at the amount billed to customers. We provide an allowance for doubtful accounts, which is based upon a review of outstanding receivables, historical collection information and existing economic conditions. Provisions for doubtful accounts are recorded when it is deemed probable that the customer will not make the required payments at either the contractual due dates or in the future.
Property, Plant and Equipment. Property, plant and equipment ("PP&E") are reported at cost less accumulated depreciation. Maintenance and repairs, which do not improve or extend the life of the related assets, are charged to expense when incurred. Refurbishments are capitalized when the value of the equipment is enhanced for an extended period. When property and equipment are sold or otherwise disposed of, the asset account and related accumulated depreciation account are relieved, and any gain or loss is included in operating income. The cost of property and equipment currently in service is depreciated, on a straight-line basis, over the estimated useful lives of the related assets.
PP&E are evaluated on a quarterly basis to identify events or changes in circumstances (“triggering events”) that indicate the carrying value of certain PP&E may not be recoverable. PP&E are reviewed for impairment upon the occurrence of a triggering event. An impairment loss is recorded in the period in which it is determined that the carrying amount of PP&E is not recoverable. The determination of recoverability is made based upon the estimated undiscounted future net cash flows of assets grouped at the lowest level for which there are identifiable cash flows independent of the cash flows of other groups of assets with such cash flows to be realized over the estimated remaining useful life of the primary asset within the asset group, excluding interest expense. We determined the lowest level of identifiable cash flows that are independent of other asset groups to be primarily at the service line level. Our asset groups consist of well support services, fracturing services, cased-hole wireline and pumping services, cementing services and coiled tubing services. If the estimated undiscounted future net cash flows for a given asset group is less than the carrying amount of the related assets, an impairment loss is determined by comparing the estimated fair value with the carrying value of the related assets. The impairment loss is then allocated across the asset group's major classifications.
Goodwill, Indefinite-Lived Intangible Assets and Definite-Lived Intangible Assets. Goodwill may be allocated across three reporting units: Completion Services, Well Construction and Intervention Services ("WC&I") and Well Support Services. At the reporting unit level, we test goodwill for impairment on an annual basis as of October 31 of each year, or when events or changes in circumstances, referred to as triggering events, indicate the carrying value of goodwill may not be recoverable and that a potential impairment exists. Judgment is used in assessing whether goodwill should be tested for impairment more frequently than annually. Factors such as unexpected adverse economic conditions, competition, market changes and other external events may require more frequent assessments.
Before employing quantitative impairment testing methodologies, we may first evaluate the likelihood of impairment by considering qualitative factors relevant to each reporting unit, such as macroeconomic, industry, market or any other factors that have a significant bearing on fair value. If we first utilize a qualitative approach and determine that it is more likely than not that goodwill is impaired, quantitative testing methodologies are then applied. Otherwise, we conclude that no impairment has occurred. Quantitative impairment testing involves comparing the fair value of each reporting unit to its carrying value, including goodwill. Fair value reflects the price a market participant would be willing to pay in a potential sale of the reporting unit. If the fair value exceeds carrying value, then it is concluded that no goodwill impairment has occurred. In connection with our adoption of ASU No. 2017-04, Simplifying the Test for Goodwill Impairment on January 1, 2018, if the carrying value of the reporting unit exceeds its fair value, an impairment loss is recognized in an amount equal to the excess, not to exceed the amount of goodwill allocated to the reporting unit.
Quantitative impairment testing involves the use of a blended income and market approach. Significant management judgment is necessary to evaluate the impact of operating and macroeconomic changes on each reporting unit.
Critical assumptions include projected revenue growth, fleet count, utilization, gross profit rates, sales, general and administrative ("SG&A") rates, working capital fluctuations, capital expenditures, discount rates, terminal growth rates, and price-to-earnings multiples. Our market capitalization is also used to corroborate reporting unit valuations.
Similar to goodwill, indefinite-lived intangible assets are subject to annual impairment tests or more frequently if events or circumstances indicate the carrying amount may not be recoverable.
Definite-lived intangible assets are amortized over their estimated useful lives and are reviewed for impairment when a triggering event occurs. With the exception of the C&J trade name, these intangibles, along with PP&E, are reviewed for impairment when a triggering event indicates that the asset group may have a net book value in excess of recoverable value. In these cases, we perform a recoverability test on our PP&E and definite-lived intangible assets by comparing the estimated future net undiscounted cash flows expected to be generated from the use of these assets to the carrying amount of the assets for recoverability. If the estimated undiscounted cash flows exceed the carrying amount of the assets, an impairment does not exist, and a loss will not be recognized. If the undiscounted cash flows are less than the carrying amount of the assets, the assets are not recoverable and the amount of impairment must be determined by fair valuing the assets. The C&J trade name is a corporate asset and is reviewed for impairment upon the occurrence of a triggering event by comparing the carrying amount of the corporate assets with the remaining cash flows available, after taking into consideration the lower level asset groups that benefit from the C&J trade name.
Mergers and Acquisitions. In accordance with accounting guidance for business combinations, we allocate the purchase price of an acquired business to its identifiable assets and liabilities based on estimated fair values. The excess of the purchase price over the amount allocated to the assets and liabilities, if any, is recorded as goodwill. We use all available information to estimate fair values. We typically engage outside appraisal firms to assist in the fair value determination of identifiable intangible assets such as trade names and any other significant assets or liabilities. We adjust the preliminary purchase price allocation, as necessary, up to one year after the acquisition closing date as we obtain more information regarding asset valuations and liabilities assumed.
Our purchase price allocation methodology contains uncertainties because it requires management to make assumptions and to apply judgment to estimate the fair value of acquired assets and liabilities. Management estimates the fair value of assets and liabilities based upon quoted market prices, the carrying value of the acquired assets and widely accepted valuation techniques, including discounted cash flows and market multiple analysis. Unanticipated events or circumstances may occur which could affect the accuracy of our fair value estimates, including assumptions regarding industry economic factors and business strategies. If actual results are materially different than the assumptions we used to determine fair value of the assets and liabilities acquired through a business combination, it is possible that adjustments to the carrying values of such assets and liabilities will have an impact on our net earnings.
See “Note 10 - Acquisitions” in Item 8 “Financial Statements and Supplementary Data” of our Annual Report on Form 10-K for the acquisition-related information associated with mergers and acquisitions completed in the last three fiscal years.
Revenue Recognition. We adopted Accounting Standards Update ("ASU") No. 2014-09, Revenue from Contracts with Customers and its related updates as codified under ASC 606, Revenue from Contracts with Customers ("ASC 606") on January 1, 2018, using the modified retrospective method for all contracts not completed as of the date of adoption. The reported results for the year ended December 31, 2018 reflect the application of ASC 606 guidance while the reported results for the corresponding prior year period were prepared under the previous guidance of ASC No. 605, Revenue Recognition ("ASC 605"). After reviewing our contracts and the revenue recognition guidance under ASC 606, there are no material differences between revenue recognition under ASC 605 and ASC 606. As a result, there is not a cumulative effect adjustment recorded to beginning retained earnings or recognition of any contract assets or liabilities upon adoption of ASC 606.
The adoption of ASC 606 represents a change in accounting principle that more closely aligns revenue recognition with the performance of our services and provides financial statement readers with enhanced disclosures. In accordance with ASC 606, revenue is recognized in a manner reflecting the transfer of goods or services to customers based on consideration a company expects to receive. We recognize revenue when we satisfy a performance obligation by transferring control over a product or service to a customer. To achieve this core principle, ASC 606 requires we apply the following five steps: (1) identify the contract with a customer, (2) identify the performance obligations in the contract, (3) determine the transaction price, (4) allocate the transaction price to performance obligations in the contract, and (5) recognize revenue when or as we satisfy a performance obligation. The five-step model requires management to exercise judgment when evaluating contracts and recognizing revenue.
Share-Based Compensation. Our share-based compensation plan provides the ability to grant equity awards to our employees, consultants and non-employee directors. As of December 31, 2018, only nonqualified stock options, restricted shares, performance stock and restricted share units had been granted under such plans. The fair value of restricted share grants and restricted share units is based on the closing price of our common stock on the grant date. We values option grants based on the grant date fair value using the Black-Scholes option-pricing model, and we value performance awards with market conditions based on the grant date fair value using a Monte Carlo simulation, both of which require the use of subjective assumptions. We recognize share-based compensation expense on a straight-line basis over the requisite service period for the entire award and makes estimates of employee terminations and forfeiture rates which impacts the amount of compensation expense that is recorded over the requisite service period.
Income Taxes. We are subject to income and other similar taxes in all areas in which we operate. When recording income tax expense, certain estimates are required because: (a) income tax returns are generally filed months after the close of our annual accounting period; (b) tax returns are subject to audit by taxing authorities and audits can often take years to complete and settle; and (c) future events often impact the timing of when we recognize income tax expenses and benefits.
We account for income taxes utilizing the asset and liability method. Under this method, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities due to a change in tax rates is recognized as income or expense in the period that includes the enactment date.
The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. In assessing the likelihood and extent that deferred tax assets will be realized, consideration is given to projected future taxable income and tax planning strategies. A valuation allowance is recorded when, in the opinion of management, it is more likely than not that a portion or all of the deferred tax assets will not be realized.
We have federal, state and international net operating losses ("NOLs") carried forward from tax years ending before January 1, 2018 that will expire in the years 2020 through 2038. Due to U.S. tax reform, any U.S. federal income tax losses incurred for tax years beginning after December 31, 2017 can be carried forward indefinitely with no carry back available. In addition, the taxable losses generated in tax years beginning after December 31, 2017 can only offset 80% of taxable income generated in tax years beginning after December 31, 2018. After considering the scheduled reversal of deferred tax liabilities, projected future taxable income, the potential limitation on use of NOLs under Section 382 of the Internal Revenue Code of 1986, as amended (the "Code") and tax planning strategies, we established a valuation allowance due to the uncertainty regarding the ultimate realization of the deferred tax assets associated with its NOL carryforwards.
As a result of the Chapter 11 Proceeding, on the Plan Effective Date, we believe we experienced an ownership change for purposes of Section 382 of the Code because of its Restructuring Plan. Consequently, our pre-change NOLs are subject to an annual limitation (See Note 14 - Chapter 11 Proceeding and Emergence for additional information, including definitions of capitalized defined terms, about the Chapter 11 Proceeding and emergence from the Chapter 11 Proceeding). The ownership change and resulting annual limitation on use of NOLs are not expected to result in the expiration of our NOL carryforwards if we are able to generate sufficient future taxable income within the carryforward periods. However, the limitation on the amount of NOLs available to offset taxable income in a specific year may result in the payment of income taxes before all NOLs have been utilized. Additionally, a subsequent ownership change may result in further limitation on the ability to utilize existing NOLs and other tax attributes, which could cause our pre-change NOL carryforwards to expire unused.
We recognize the financial statement effects of a tax position when it is more-likely-than-not, based on the technical merits, that the position will be sustained upon examination. A tax position that meets the more-likely-than-not recognition threshold is measured as the largest amount of tax benefit that is greater than 50.0% likely of being realized upon ultimate settlement with a taxing authority. Previously recognized uncertain tax positions are reversed in the first period in which it is more-likely-than-not that the tax position would be sustained upon examination. Income tax related interest and penalties, if applicable, are recorded as a component of the provision for income tax expense. For the year ended December 31, 2018, we have an unrecognized tax benefit of $6.0 million related to an increase in the estimate of the reserve for unrecognized tax benefits relating to our uncertain tax positions, which is netted against our net operating loss carryforwards. The unrecognized tax benefit, or UTB, is related to a deduction for certain fees that were paid using shares of our common stock as part of the January 7, 2017 plan of reorganization. The recorded unrecognized tax benefit is equal to our estimate of the portion of the tax benefit that is less than 50% likely to be realized upon ultimate settlement with a taxing
authority.
Recent Accounting Pronouncements
In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) ("ASU 2016-02"). ASU No. 2016-02 seeks to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and by disclosing key information about leasing arrangements. Unlike current U.S. GAAP, which requires only capital leases to be recognized on the balance sheet, ASU No. 2016-02 will require both operating and finance leases to be recognized on the balance sheet. Additionally, the new guidance will require disclosures to help investors and other financial statement users better understand the amount, timing, and uncertainty of cash flows arising from leases, including qualitative and quantitative requirements.
The amendments in ASU No. 2016-02 are effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years, and early application is permitted. We adopted this new accounting standard on January 1, 2019 using the modified retrospective approach. Under this transition method, leases existing at, or entered into after the adoption date are required to be recognized and measured. We have elected to use the effective date as its date of initial application, consequently prior period amounts have not been adjusted and continue to be reflected in accordance with historical accounting. We elected the package of practical expedients which permits us to not reassess under the new standard our prior conclusions about lease identification, lease classification and initial direct costs. We have also elected the practical expedient to combine the lease and non-lease components of a contract for all of our contracts, as well as the short-term lease recognition exemption.
The adoption of this standard will result in the initial recognition of approximately $25.0 million to $28.0 million of right-of-use assets and operating lease liabilities, with no related impact to consolidated stockholders' equity or net income (loss).
In June 2016, the FASB issued ASU No. 2016-13, Financial Instruments-Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments (“ASU 2016-13”), which amends U.S. GAAP by introducing a new impairment model for financial instruments that is based on expected credit losses rather than incurred credit losses. The new impairment model applies to most financial assets, including trade accounts receivable. The amendments in ASU 2016-13 are effective for interim and annual reporting periods beginning after December 15, 2019, although it may be adopted one year earlier, and requires a modified retrospective transition approach. We are currently evaluating the impact this standard will have on our results of operations and financial position.
In October 2016, the FASB issued ASU No. 2016-16, Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other Than Inventory ("ASU 2016-16"), which requires an entity to recognize the income tax consequences of an intra-entity asset transfer, other than an intra-entity asset transfer of inventory, when the transfer occurs. The ASU is effective for the interim and annual reporting periods beginning after December 15, 2017, including interim periods within those fiscal years, and early application is permitted. We adopted this new accounting standard on January 1, 2018, and upon adoption recognized a cumulative effect adjustment as a reduction to retained earnings of $13.2 million.
In January 2017, the FASB issued ASU No. 2017-04, Intangibles-Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment ("ASU 2017-04"), which establishes a one-step process for testing goodwill for impairment. This ASU is effective for the interim and annual reporting periods beginning after December 15, 2019 and early adoption is permitted. We early adopted this new accounting standard on January 1, 2018 and there no impact on our consolidated financial statements upon adoption. As part of our annual impairment assessment of goodwill during the fourth quarter of 2018, we applied this new accounting standard and recognized an impairment charge of $146.0 million for the year ended December 31, 2018.
In February 2018, the FASB issued ASU No. 2018-02, Income Statement - Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income ("ASU 2018-02"), which allows for a reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the Tax Cuts and Jobs Act and requires certain disclosures about stranded tax effects. This ASU is effective for the interim and annual reporting periods beginning after December 15, 2019, and early adoption is permitted. We are currently evaluating the impact of this standard on our consolidated financial statements.
In March 2018, the FASB issued ASU No. 2018-05, Income Taxes (Topic 740): Amendments to SEC Paragraphs Pursuant to SEC Staff Accounting Bulletin No. 118, ("ASU 2018-05"), which provides guidance on accounting for the tax effects of the Tax Cuts and Jobs Act (the Tax Act) pursuant to Staff Accounting Bulletin No. 18, which allows companies to
complete the accounting under ASC 740 within a one-year measurement period from the Tax Act enactment date. This standard is effective upon issuance. We adopted this new accounting standard January 1, 2018, and there was no impact on our consolidated financial statements upon adoption.
In June 2018, the FASB issued ASU No. 2018-07, Compensation-Stock Compensation (Topic 718): Improvements to Nonemployee Share-Based Payment Accounting, ("ASU 2018-07"), which expands the scope of Topic 718 to include all share-based payment transactions for acquiring goods and services from nonemployees. This ASU is effective for the interim and annual reporting periods beginning after December 15, 2018, and early adoption is permitted. We adopted this new accounting standard January 1, 2019, and there was no impact on our consolidated financial statements upon adoption.
In August 2018, the FASB issued ASU No. 2018-13, Fair Value Measurement (Topic 820): Disclosure Framework-Changes to the Disclosure Requirements for Fair Value Measurement ("ASU 2018-13"), which modifies the disclosure requirements for fair value measurements by removing, modifying, or adding certain disclosures. This ASU is effective for the interim and annual reporting periods beginning after December 15, 2019, and early adoption is permitted. We are currently evaluating the impact of this standard on our consolidated financial statements.
In August 2018, the FASB issued ASU No. 2018-15, Intangibles - Goodwill and Other Internal-Use Software (Subtopic 350-50): Customer's Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That is a Service Contract ("ASU 2018-15"), which aligns the requirements for capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software. This ASU is effective for the interim and annual reporting periods beginning after December 15, 2019, and early adoption is permitted. We are currently evaluating the impact of this standard on our consolidated financial statements.
Inflation
Inflation in the United States has been relatively low in recent years and did not have a material impact on our results of operations for the years ended December 31, 2018, 2017 and 2016. Although the impact of inflation has been insignificant in recent years, it is still a factor in the U.S. economy, and we tend to experience inflationary pressure on the cost of our equipment, materials and supplies as increasing oil and natural gas prices increase activity in our areas of operations.
Item 7A.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Market risk is the risk of loss arising from adverse changes in market rates and prices. The principal market risk to which we are exposed is commodity price risk, which is the risk related to increases in the prices of fuel, materials and supplies consumed in performing our services. We are also exposed to risks related to interest rate fluctuations and customer credit.
Commodity Price Risk. Our material and fuel purchases expose us to commodity price risk. Our material costs primarily include the cost of inventory consumed while performing our stimulation services such as proppants, chemicals, guar, coiled tubing and fluid supplies. Our fuel costs consist primarily of diesel fuel used by our various trucks and other motorized equipment. The prices for fuel and the raw materials (particularly guar and proppants) in our inventory are volatile and are impacted by changes in supply and demand, as well as market uncertainty and regional shortages. Historically, we have generally been able to pass along price increases to our customers; however, we may be unable to do so in the future. We do not engage in commodity price hedging activities.
Interest Rate Risk. We are exposed to changes in interest rates on our floating rate borrowings under our Credit Facility. As of December 31, 2018, we had no debt outstanding under our Credit Facility. The impact of a 1.0% increase in interest rates under the terms of the Credit Facility would have no impact on interest expense for the 2018 year.
Customer Credit Risk. Financial instruments that potentially subject us to concentrations of credit risk are trade receivables. We extend credit to customers and other parties in the normal course of business. We have established various procedures to manage our credit exposure, including credit evaluations and maintaining an allowance for doubtful accounts.
Item 8.
Item 8. Financial Statements and Supplementary Data
Index to
Consolidated Financial Statements
Management’s Report on Internal Control Over Financial Reporting
Management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act). Internal control over financial reporting is a process designed by, or under the supervision of, the Company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the Company’s board of directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles in the United States and includes those policies and procedures that (i) pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of the assets of the Company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Management with the participation of the Company’s principal executive and financial officers assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2018. In making this assessment, it used the criteria set forth in 2013 by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework. Management’s assessment included an evaluation of the design of internal control over financial reporting and testing of the operational effectiveness of its internal control over financial reporting. Based on this assessment, management has concluded that the Company maintained effective internal control over financial reporting as of December 31, 2018.
The Company's internal control over financial reporting as of December 31, 2018 has been audited by KPMG LLP, an independent registered public accounting firm, as stated in their report which appears in this Form 10-K.
/s/ Donald J. Gawick
/s/ Jan Kees van Gaalen
/s/ Michael S. Galvan
Donald J. Gawick
President, Chief Executive Officer and Director (Principal Executive Officer)
Jan Kees van Gaalen
Chief Financial Officer (Principal Financial Officer)
Michael S. Galvan
Chief Accounting Officer and Treasurer
(Principal Accounting Officer)
February 27, 2019
Report of Independent Registered Public Accounting Firm
To the Stockholders and Board of Directors
C&J Energy Services, Inc.:
Opinion on the Consolidated Financial Statements
We have audited the accompanying consolidated balance sheets of C&J Energy Services, Inc. (the Company) as of December 31, 2018 and 2017, the related consolidated statements of operations, comprehensive income (loss), shareholders’ equity, and cash flows for the years ended December 31, 2018 and 2017 (Successor), and for the year ended 2016 (Predecessor), and the related notes (collectively, the consolidated financial statements). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2018 and 2017, and the results of its operations and its cash flows for the years ended December 31, 2018 and 2017 (Successor) and for the year ended 2016 (Predecessor), in conformity with U.S. generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated February 27, 2019 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.
Basis for Opinion
These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion provide a reasonable basis for our opinion.
/s/ KPMG LLP
We have served as the Company's auditor since 2014.
Houston, Texas
February 27, 2019
Report of Independent Registered Public Accounting Firm
To the Stockholders and Board of Directors
C&J Energy Services, Inc.:
Opinion on Internal Control Over Financial Reporting
We have audited C&J Energy Services, Inc.’s (the Company) internal control over financial reporting as of December 31, 2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of the Company as of December 31, 2018 and 2017, and the related consolidated statements of operations, comprehensive income (loss), shareholders’ equity, and cash flows for the years ended December 31, 2018 and 2017 (Successor), and for the year ended December 31, 2016 (Predecessor), and related notes (collectively, the consolidated financial statements), and our report dated February 27, 2019 expressed an unqualified opinion on those consolidated financial statements.
Basis for Opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the 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 audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control Over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ KPMG LLP
Houston, Texas
February 27, 2019
C&J ENERGY SERVICES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(In thousands, except share data)
See accompanying notes to consolidated financial statements
C&J ENERGY SERVICES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per share data)
See accompanying notes to consolidated financial statements
C&J ENERGY SERVICES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(In thousands)
See accompanying notes to consolidated financial statements
C&J ENERGY SERVICES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY
(In thousands)
See accompanying notes to consolidated financial statements
C&J ENERGY SERVICES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
See accompanying notes to consolidated financial statements
C&J ENERGY SERVICES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1 - Organization, Nature of Business and Summary of Significant Accounting Policies
C&J Energy Services, Inc., a Delaware corporation (the “Successor” and together with its consolidated subsidiaries for periods subsequent to the Plan Effective Date (as defined below), “C&J” or the “Company”), is a leading provider of new well construction, well completion, well support and other complementary oilfield services to oil and gas exploration and production ("E&P") companies throughout the continental United States. The Company offers a comprehensive suite of services throughout the life cycle of the well, including hydraulic fracturing, cased-hole wireline and pumping, cementing, coiled tubing, rig services, fluids management, and other completion and well support services. The Company is headquartered in Houston, Texas, and operates across all active onshore basins in the continental United States.
C&J’s business was founded in Texas in 1997 as a partnership and converted to a Delaware corporation (“Old C&J”) in connection with an initial public offering which was completed in 2011 with a listing on the New York Stock Exchange (“NYSE”) under the symbol “CJES.” Beginning in 2011 through mid-2015, the Company significantly invested in a number of strategic initiatives to strengthen, expand and diversify its business, including through service line diversification, vertical integration and technological advancement. In 2015, Old C&J combined with the completion and production services business (the “C&P Business”) of Nabors Industries Ltd. (“Nabors”) in a transformative transaction (the “Nabors Merger”) that significantly expanded the Company’s Completion Services and Well Construction and Intervention Services businesses and added the Well Support Services division to the Company’s service offering. Upon the closing of the Nabors Merger, Old C&J became a subsidiary of C&J Energy Services Ltd., a Bermuda corporation (the “Predecessor” and together with its consolidated subsidiaries for periods prior to the Plan Effective Date, the “Predecessor Companies,” or the “Company”).
Due to the severe industry downturn, on July 20, 2016 (the "Petition Date"), the Predecessor Companies voluntarily filed petitions for reorganization seeking relief under the provisions of Chapter 11 of the United States Bankruptcy Code in the United States Bankruptcy Court for the Southern District of Texas, Houston Division (the "Bankruptcy Court"), with ancillary recognition proceedings filed in Canada and Bermuda (collectively, the "Chapter 11 Proceeding").
The plan of reorganization (the “Restructuring Plan”) of the Predecessor Companies was confirmed in December 2016, and on January 6, 2017 (the “Plan Effective Date”), the Predecessor Companies substantially consummated the Restructuring Plan and emerged from the Chapter 11 Proceeding. Pursuant to the Restructuring Plan, effective on the Plan Effective Date, the Predecessor’s equity was canceled, the Predecessor transferred all of its assets and operations to the Successor and the Predecessor was subsequently dissolved. The Predecessor’s common stock was ultimately delisted from the NYSE. On April 12, 2017, the Successor completed an underwritten public offering of common stock and its common stock began trading again on the NYSE under the symbol “CJ.”
Upon emergence from the Chapter 11 Proceeding, the Company adopted fresh start accounting ("Fresh Start"). For more information regarding the Chapter 11 Proceeding and adoption of Fresh Start accounting, see Note 14 - Chapter 11 Proceeding and Emergence and Note 15 - Fresh Start Accounting.
Basis of Presentation and Principles of Consolidation
The consolidated financial statements have been prepared in conformity with accounting principles generally accepted in the United States of America (“U.S. GAAP”) and include all of the accounts of C&J and its consolidated subsidiaries. All significant inter-company transactions and account balances have been eliminated upon consolidation.
As discussed above the Company adopted Fresh Start accounting in accordance with the provisions set forth in ASC 852 with respect to the accounting and financial statement disclosures. Accordingly, the Company's consolidated financial statements and notes prior to January 1, 2017, ("Fresh Start Reporting Date") are not comparable to the consolidated financial statements as of January 1, 2017 and periods subsequent to January 1, 2017.
C&J ENERGY SERVICES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Summary of Significant Accounting Policies
Use of Estimates. The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenue and expenses during the reporting period. Estimates are used in, but are not limited to, determining the following: allowance for doubtful accounts, valuation of long-lived assets including intangibles, goodwill, useful lives used in depreciation and amortization, inventory reserves, income taxes, share-based compensation and liabilities subject to compromise under the provisions of ASC 852 Fresh Start. The accounting estimates used in the preparation of the consolidated financial statements may change as new events occur, as more experience is acquired, or as additional information is obtained and as the Company’s operating environment changes.
Cash and Cash Equivalents. For purposes of the consolidated statement of cash flows, cash is defined as cash on-hand, demand deposits, and short-term investments with initial maturities of three months or less. The Company maintains its cash and cash equivalents in various financial institutions, which at times may exceed federally insured amounts. Management believes that this risk is not significant. Cash balances related to the Company's captive insurance subsidiaries, which totaled $19.7 million and $23.8 million at December 31, 2018 and December 31, 2017, respectively, are included in cash and cash equivalents in the consolidated balance sheets, and the Company expects to use these cash balances to fund the operations of the captive insurance subsidiaries and to settle future anticipated claims.
Accounts Receivable and Allowance for Doubtful Accounts. Accounts receivable are generally stated at the amount billed to customers. The Company provides an allowance for doubtful accounts, which is based upon a review of outstanding receivables, historical collection information and existing economic conditions. Provisions for doubtful accounts are recorded when it is deemed probable that the customer will not make the required payments at either the contractual due dates or in the future. At December 31, 2018 and 2017, the allowance for doubtful accounts totaled $4.9 million and $4.3 million, respectively. Bad debt expense of $1.5 million, $4.4 million and $1.7 million was included in direct costs on the consolidated statements of operations for the years ended December 31, 2018, 2017 and 2016, respectively.
Inventories. Inventories are carried at the lower of cost or net realizable value. Inventories for the Company consist of raw materials, work-in-process and finished goods, including equipment parts, chemicals, proppants, supplies and materials for the Company's operations.
Consistent with FASB requirements under ASC 852, an entity adopting Fresh Start may generally set new accounting policies for the successor independent of those followed by the predecessor. The entity emerging from bankruptcy typically is not required to demonstrate preferability for its new accounting policies, as the successor entity represents a new entity for financial reporting purposes.
During January 2017, the Company implemented a new computer system that provides financial reporting, inventory management and fixed asset management capabilities (the "new ERP system") to enhance functionality and to support the Company's existing and future operations. The new ERP system utilizes the weighted average cost flow method for determining inventory cost ("Weighted Average"), which replaced the first-in, first-out basis ("FIFO") method utilized by the Predecessor's legacy system. The Weighted Average and FIFO methods are both allowable under U.S. GAAP. As of the Fresh Start Reporting Date, the Company began utilizing the Weighted Average method for determining inventory cost. Inventory cost for the periods prior to the Fresh Start Reporting Date are presented under the FIFO method.
Inventories consisted of the following:
C&J ENERGY SERVICES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Property, Plant and Equipment. Property, plant and equipment ("PP&E") are reported at cost less accumulated depreciation. Maintenance and repairs, which do not improve or extend the life of the related assets, are charged to expense when incurred. Refurbishments are capitalized when the value of the equipment is enhanced for an extended period. When property and equipment are sold or otherwise disposed of, the asset account and related accumulated depreciation account are relieved, and any gain or loss is included in operating income.
The cost of property and equipment currently in service is depreciated, on a straight-line basis, over the estimated useful lives of the related assets, which range from three to 25 years. Depreciation expense was $216.1 million, $136.5 million, and $206.7 million for the years ended December 31, 2018, 2017 and 2016, respectively. Major classifications of PP&E and their respective useful lives are as follows:
PP&E are evaluated on a quarterly basis to identify events or changes in circumstances (“triggering events”) that indicate the carrying value of certain PP&E may not be recoverable. PP&E are reviewed for impairment upon the occurrence of a triggering event. An impairment loss is recorded in the period in which it is determined that the carrying amount of PP&E is not recoverable. The determination of recoverability is made based upon the estimated undiscounted future net cash flows of assets grouped at the lowest level for which there are identifiable cash flows independent of the cash flows of other groups of assets with such cash flows to be realized over the estimated remaining useful life of the primary asset within the asset group, excluding interest expense. The Company determined the lowest level of identifiable cash flows that are independent of other asset groups to be primarily at the service line level. The Company's asset groups consist of well support services, fracturing services, cased-hole wireline and pumping services, cementing services and coiled tubing services. If the estimated undiscounted future net cash flows for a given asset group is less than the carrying amount of the related assets, an impairment loss is determined by comparing the estimated fair value with the carrying value of the related assets. The impairment loss is then allocated across the asset group's major classifications.
During the fourth quarter of 2018, in connection with the Company's annual test for goodwill impairment discussed below, the Company deemed the deficit of the Well Support Services reporting unit book value of equity over its concluded fair value of equity to be a triggering event requiring recoverability testing of the asset groups within this reporting unit. Based on the results of the recoverability test, undiscounted net cash flows were in excess of the carrying amount of the related assets, and no impairment was indicated.
In 2016, the Company concluded that the effects from the sharp fall in commodity prices during the second half of 2014 and throughout 2015 constituted a triggering event that resulted in a significant slowdown in activity across the Company’s customer base, which in turn increased competition and put pressure on pricing for its services throughout 2016. As a result of the triggering event that continued throughout 2015 and 2016, PP&E recoverability testing was performed during those two years. During 2016, the recoverability testing for the asset groups coiled tubing, cementing, and subsequently divested businesses including directional drilling, artificial lift applications and international coiled tubing yielded an estimated undiscounted net cash flow that was less than the carrying amount of the related assets. The estimated fair value for each respective asset group was compared to its carrying value, and impairment expense of $61.1 million was recognized during 2016 and allocated across each respective asset group's major classification. The impairment charge was primarily related to underutilized equipment. The fair value of these assets was based on the projected present value of future cash flows that these
C&J ENERGY SERVICES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
assets are expected to generate. No impairment charge related to the Company's PP&E was recorded for the years ended December 31, 2018 and 2017.
During the fourth quarter of 2018, the Company retired certain assets, primarily within the fracturing, coiled tubing and well support services asset groups, that were deemed to be obsolete with unfavorable economics for refurbishment based on prevailing customer preferences and current market conditions. The year ended December 31, 2018 includes a charge of $21.4 million related to these retirements and was included within (gain) loss on disposal of assets on the consolidated statements of operations. During 2017, the Company recorded a $31.5 million gain on disposal of assets, which was primarily related to the sale of assets associated with its Canadian rig services business and its divested equipment manufacturing business.
Goodwill, Indefinite-Lived Intangible Assets and Definite-Lived Intangible Assets. Goodwill may be allocated across three reporting units: Completion Services, Well Construction and Intervention Services ("WC&I") and Well Support Services. At the reporting unit level, the Company tests goodwill for impairment on an annual basis as of October 31 of each year, or when events or changes in circumstances, referred to as triggering events, indicate the carrying value of goodwill may not be recoverable and that a potential impairment exists.
Judgment is used in assessing whether goodwill should be tested for impairment more frequently than annually. Factors such as unexpected adverse economic conditions, competition, market changes and other external events may require more frequent assessments. During the fourth quarter of 2018, a significant decline in the Company's share price, which resulted in the Company's market capitalization dropping below its book value of equity, as well as an overall decrease in commodity prices were deemed triggering events that led to a test for goodwill impairment. See Note 3 - Goodwill and Other Intangible Assets for further discussion on impairment testing results.
Before employing quantitative impairment testing methodologies, the Company may first evaluate the likelihood of impairment by considering qualitative factors relevant to each reporting unit, such as macroeconomic, industry, market or any other factors that have a significant bearing on fair value. If the Company first utilizes a qualitative approach and determines that it is more likely than not that goodwill is impaired, quantitative testing methodologies are then applied. Otherwise, the Company concludes that no impairment has occurred. Quantitative impairment testing involves comparing the fair value of each reporting unit to its carrying value, including goodwill. Fair value reflects the price a market participant would be willing to pay in a potential sale of the reporting unit. If the fair value exceeds carrying value, then it is concluded that no goodwill impairment has occurred. In connection with the Company's adoption of ASU No. 2017-04, Simplifying the Test for Goodwill Impairment on January 1, 2018, if the carrying value of the reporting unit exceeds its fair value, an impairment loss is recognized in an amount equal to the excess, not to exceed the amount of goodwill allocated to the reporting unit.
Quantitative impairment testing involves the use of a blended income and market approach. Significant management judgment is necessary to evaluate the impact of operating and macroeconomic changes on each reporting unit. Critical assumptions include projected revenue growth, fleet count, utilization, gross profit rates, sales, general and administrative ("SG&A") rates, working capital fluctuations, capital expenditures, discount rates, terminal growth rates, and price-to-earnings multiples. The Company’s market capitalization is also used to corroborate reporting unit valuations.
Similar to goodwill, indefinite-lived intangible assets are subject to annual impairment tests or more frequently if events or circumstances indicate the carrying amount may not be recoverable. As of December 31, 2018 and 2017, the Company had no indefinite-lived intangible assets.
Definite-lived intangible assets are amortized over their estimated useful lives and are reviewed for impairment when a triggering event occurs. With the exception of the C&J trade name, these intangibles, along with PP&E, are reviewed for impairment when a triggering event indicates that the asset group may have a net book value in excess of recoverable value. In these cases, the Company performs a recoverability test on its PP&E and definite-lived intangible assets by comparing the estimated future net undiscounted cash flows expected to be generated from the use of these assets to the carrying amount of the assets for recoverability. If the estimated undiscounted cash flows exceed the carrying amount of the assets, an impairment does not exist, and a loss will not be recognized. If the undiscounted cash flows are less than the carrying amount of the assets, the assets are not recoverable and the amount of impairment must be determined by fair valuing the assets. The C&J trade name is a corporate asset and is reviewed for impairment upon the occurrence of a triggering event by comparing the carrying amount of the corporate assets with the remaining cash flows available, after taking into consideration the lower level asset groups that benefit from the C&J trade name.
For further discussion of the application of this accounting policy regarding impairments, please see Note 3 -
C&J ENERGY SERVICES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Goodwill and Other Intangible Assets.
Deferred Financing Costs. Costs incurred to obtain revolver based financing are capitalized and amortized over the term of the loan using the effective interest method. Costs incurred to obtain non-revolver based debt financing are presented on the balance sheet as a direct deduction from the carrying amount of the term debt, consistent with debt discounts, and accreted over the term of the loan using the effective interest method. These costs are classified within interest expense on the consolidated statements of operations and were $2.3 million, $0.6 million and $100.7 million for the years ended December 31, 2018, 2017 and 2016, respectively. Accumulated amortization of deferred financing costs was $2.9 million and $0.6 million at December 31, 2018 and 2017, respectively.
Revenue Recognition. The Company adopted Accounting Standards Update ("ASU") No. 2014-09, Revenue from Contracts with Customers and its related updates as codified under ASC 606, Revenue from Contracts with Customers ("ASC 606") on January 1, 2018, using the modified retrospective method for all contracts not completed as of the date of adoption. The reported results for the year ended December 31, 2018 reflect the application of ASC 606 guidance while the reported results for the corresponding prior year period were prepared under the previous guidance of ASC No. 605, Revenue Recognition ("ASC 605"). After reviewing the Company's contracts and the revenue recognition guidance under ASC 606, there are no material differences between revenue recognition under ASC 605 and ASC 606. As a result, there is not a cumulative effect adjustment recorded to beginning retained earnings or recognition of any contract assets or liabilities upon adoption of ASC 606.
The adoption of ASC 606 represents a change in accounting principle that more closely aligns revenue recognition with the performance of the Company's services and provides financial statement readers with enhanced disclosures. In accordance with ASC 606, revenue is recognized in a manner reflecting the transfer of goods or services to customers based on consideration a company expects to receive. The Company recognizes revenue when it satisfies a performance obligation by transferring control over a product or service to a customer. To achieve this core principle, ASC 606 requires the Company to apply the following five steps: (1) identify the contract with a customer, (2) identify the performance obligations in the contract, (3) determine the transaction price, (4) allocate the transaction price to performance obligations in the contract, and (5) recognize revenue when or as the Company satisfies a performance obligation. The five-step model requires management to exercise judgment when evaluating contracts and recognizing revenue.
Identify the Contract and Determine Transaction Price
The Company typically provides its services (i) under term pricing agreements; (ii) under contracts that include dedicated fleet or unit arrangements; (iii) on a spot market basis; and (iv) under term contracts that include “take-or-pay” provisions.
Under term pricing agreements, the Company and customer agree to set pricing for a specified period of time. The agreed-upon pricing is subject to periodic review, as specifically defined in the agreement, and may be adjusted upon the agreement of both parties. These agreements typically do not feature provisions obligating either party to commit to a certain utilization level. Additionally, these agreements typically allow either party to terminate the agreement for its convenience without incurring a termination penalty.
Under dedicated fleets or unit arrangements, customers typically commit to targeted utilization levels based on a specified number of fracturing stages per calendar month or fulfilling the customer's requirements, in either instance at agreed-upon pricing. These agreements typically do not feature obligations to pay for services not used by the customer. In addition, the agreed-upon pricing is typically subject to periodic review, as specifically defined in the agreement, and may be adjusted upon the agreement of both parties. These contracts also typically allow for termination for either party's convenience with a brief notice period and may feature a termination penalty in the event the customer terminates the contract for its convenience.
Rates for services performed on a spot market basis are based on an agreed-upon spot market rate for each stage the Company fractures.
Under term contracts with “take-or-pay” provisions, the Company’s customers are typically obligated to pay on a monthly basis for a specified quantity of services, whether or not those services are actually utilized. To the extent customers use more than the specified contracted minimums, the Company will charge a pre-agreed amount for the provision of such additional services, which amounts are typically subject to periodic review. In addition, these contracts typically feature a termination penalty in the event the customer terminates the contract for its convenience.
C&J ENERGY SERVICES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
"Take-or-pay" provisions are considered stand ready performance obligations. The Company recognizes "take-or-pay" revenues using a time-based measure of progress, as the Company cannot reasonably estimate if and when the customer will require the use of the Company’s fleet to provide the fracturing services; likewise, the customer can benefit when a well needs fracturing services from the fleet which is standing by to provide such services.
Identify and Satisfy the Performance Obligations
The majority of the Company’s performance obligations are satisfied over time. The Company has determined this best represents the transfer of value from its services to the customer as performance by the Company helps to enhance a customer controlled asset (e.g., unplugging a well, enabling a well to produce oil or natural gas). Measurement of the satisfaction of the performance obligation is measured using the output method, which is typically evidenced by a field ticket. A field ticket includes items such as services performed, consumables used, and man hours incurred to complete the job for the customer. Each field ticket is used to invoice customers. Payment terms for invoices issued are in accordance with a master services agreement with each customer, which typically require payment within 30 days of the invoice issuance.
A portion of the Company’s contracts contain variable consideration; however, this variable consideration is typically unknown at the time of contract inception, and is not known until the job is complete, at which time the variability is resolved. Examples of variable consideration include the number of hours that will be incurred and the amount of consumables (such as chemicals and proppants) that will be used to complete a job.
In the course of providing services to its customers, the Company may use consumables; for example, in the Company’s fracturing business, chemicals and proppants are used in the fracturing service for the customer. ASC 606 requires that goods or services promised to a customer be identified separately when they are distinct within the contract. However, the consumables are used to complete the service for the customer and are not beneficial to the customer on their own. As such, the consumables are not a separate performance obligation, but instead are combined with the other services within the context of the contract and accounted for as a single performance obligation.
Remaining Performance Obligations
The Company invoices its customers for the services provided at contractual rates multiplied by the applicable unit of measurement, including volume of consumables used and hours incurred. In accordance with ASC 606, the Company has elected the “Right to Invoice” practical expedient for all contracts, which allows the Company to invoice its customers in an amount that corresponds directly with the value to the customer of the entity’s performance completed to date. With this election, the Company is not required to disclose information about the variable consideration related to its remaining performance obligations. For those contracts with a term of more than one year, the Company had approximately $25.0 million of unsatisfied performance obligations as of December 31, 2018, which will be recognized as services are performed over the remaining contractual terms.
Contract Balances
Accounts receivable as presented on the Company’s consolidated balance sheets represent amounts due from customers for services provided. Bad debt expense of $1.5 million, $4.4 million and $1.7 million was included as a component of direct costs on the consolidated statements of operations for the years ended December 31, 2018, 2017 and 2016, respectively.
The Company does not have any contracts in which it performs services for customers and payment for those services are contingent upon a future event (e.g., satisfaction of another performance obligation). As such, there are no contingent revenues or other contract assets recorded in the financial statements.
The Company does not have any significant contract costs to obtain or fulfill contracts with customers; as such, no amounts are recognized on the consolidated balance sheet.
The following is a description of the Company’s core service lines separated by reportable segments from which the Company generates its revenue. For additional detailed information regarding reportable segments, see Note 7 - Segment Information.
C&J ENERGY SERVICES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Completion Services Segment
Fracturing Services Revenue. Through its fracturing service line, the Company provides fracturing services (i) under term pricing agreements; (ii) under contracts that include dedicated fleet arrangements; (iii) on a spot market basis; or (iv) under term contracts that include "take-or-pay" provisions. Revenue is typically recognized, and customers are invoiced upon the completion of each job, which can consist of one or more fracturing stages. Once a job has been completed, a field ticket is generated that includes charges for the services performed and the consumables (such as chemicals and proppants) used during the course of service. The field tickets may also include charges any additional equipment used on the job and other miscellaneous consumables.
Cased-hole Wireline & Pumping Services Revenue. Through its cased-hole wireline & pumping services business, the Company provides cased-hole wireline, pumping, wireline logging, perforating, well site make-up and pressure testing and other complementary services, typically on a spot market basis. Jobs for these services are typically short-term in nature, lasting anywhere from a few hours to multiple days. The Company typically charges the customer for these services on a per job basis at agreed-upon spot market rates. Revenue is recognized based on a field ticket issued upon the completion of the job.
Other Completion Services Revenue. The Company generates revenue from its research and technology ("R&T") department, which is primarily engaged in the engineering and production of certain parts and components, such as perforating guns and addressable switches, which are used in the completion process. For R&T, the performance obligation is satisfied at a point in time.
The Company recognizes revenue at the point in time in which each order of parts and components are delivered to and accepted by the customer because the customer obtains control along with the risks and rewards of ownership of the products at such time. Once delivered, the Company has the right to invoice the customer.
Well Construction and Intervention Services Segment
Cementing Services Revenue. The Company provides cementing services on a spot market or project basis. Jobs for these services are typically short-term in nature and are generally completed in a few hours. The Company typically charges the customer for these services on a per job basis at agreed-upon spot market rates or agreed-upon job pricing for a particular project. Revenue is recognized, and customers are invoiced upon the completion of each job based on a field ticket, which includes charges for the service performed and the consumables used during the course of service.
Coiled Tubing Services Revenue. The Company provides a range of coiled tubing services primarily used for fracturing plug drill-out during completion operations and for well workover and maintenance, primarily on a spot market basis. Jobs for these services are typically short-term in nature, lasting anywhere from a few hours to multiple days. Revenue is recognized upon completion of each day’s work based upon a completed field ticket. The field ticket includes charges for the services performed and the consumables used during the course of service. The field ticket may also include charges for the mobilization and set-up of equipment, the personnel on the job, any additional equipment used on the job, and other miscellaneous consumables. The Company typically charges the customer for the services performed and resources provided on an hourly basis at agreed-upon spot market rates or pursuant to pricing agreements.
Well Support Services Segment
Rig Services Revenue. Through its rig service line, the Company provides workover and well servicing rigs that are primarily used for routine repair and maintenance of oil and gas wells, re-drilling operations and plug and abandonment operations. These services are provided on an hourly basis at prices that approximate spot market rates. Revenue is recognized, and a field ticket is generated upon the earliest of the completion of a job or at the end of each day. A rig services job can last anywhere from a few hours to multiple days depending on the type of work being performed. The field ticket includes the base hourly rate charge and, if applicable, charges for additional personnel or equipment not contemplated in the base hourly rate. The field ticket may also include charges for the mobilization and set-up of equipment.
Fluids Management Services Revenue. Through its fluids management service line, the Company primarily provides storage, transportation and disposal services for fluids used in the drilling, completion and workover of oil and gas wells. Rates for these services vary and can be on a per job, per hour, or per load basis, or on the basis of quantities sold or disposed. Revenue is recognized upon the completion of each job or load, or delivered product, based on a completed field ticket.
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Other Special Well Site Services Revenue. Through its other special well site service line, the Company primarily provides fishing, contract labor and tool rental services for completion and workover of oil and gas wells. Rates for these services vary and can be on a per job, per hour or on the basis of rental days per month. Revenue is recognized based on a field ticket issued upon the completion of each job or on a monthly billing for rental services provided.
Disaggregation of Revenue
The following tables disaggregate revenue by the Company's reportable segments, core service lines and geography:
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Share-Based Compensation. The Company’s share-based compensation plan provides the ability to grant equity awards to the Company’s employees, consultants and non-employee directors. As of December 31, 2018, only nonqualified stock options, restricted shares, performance stock and restricted share units had been granted under such plans. The fair value of restricted share grants and restricted share units is based on the closing price of C&J’s common stock on the grant date. The Company values option grants based on the grant date fair value using the Black-Scholes option-pricing model, and the
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Company values performance awards with market conditions based on the grant date fair value using a Monte Carlo simulation, both of which require the use of subjective assumptions. The Company recognizes share-based compensation expense on a straight-line basis over the requisite service period for the entire award and makes estimates of employee terminations and forfeiture rates which impacts the amount of compensation expense that is recorded over the requisite service period. Further information regarding the Company’s share-based compensation arrangements and the related accounting treatment can be found in Note 5 - Stockholders' Equity.
Fair Value of Financial Instruments. The Company’s financial instruments consist of cash and cash equivalents, accounts receivable and accounts payable. The recorded values of cash and cash equivalents, accounts receivable and accounts payable approximate their fair values given the short-term nature of these instruments.
Equity Method Investments. The Company has investments in joint ventures which are accounted for under the equity method of accounting as the Company has the ability to exercise significant influence over operating and financial policies of the joint venture. Judgment regarding the level of influence over each equity method investment includes considering key factors such as ownership interest, representation on the board of directors, participation in policy-making decisions and material intercompany transactions. Under the equity method, original investments are recorded at cost and adjusted by the Company’s share of undistributed earnings and losses of these investments. The Company eliminates all significant intercompany transactions, including the intercompany portion of transactions with equity method investees, from the consolidated financial results.
The carrying value of the Company's equity method investments at December 31, 2018 and 2017. was $1.7 million and $2.8 million, respectively, and is included in other noncurrent assets on the consolidated balance sheets. The Company’s share of the net income (loss) from the unconsolidated affiliates was approximately ($1.1) million, ($0.1) million and ($5.7) million the years ended December 31, 2018, 2017 and 2016, respectively, and is included in other income (expense), net, on the consolidated statements of operations.
Income Taxes. The Company is subject to income and other similar taxes in all areas in which they operate. When recording income tax expense, certain estimates are required because: (a) income tax returns are generally filed months after the close of the Company's annual accounting period; (b) tax returns are subject to audit by taxing authorities and audits can often take years to complete and settle; and (c) future events often impact the timing of when the Company recognizes income tax expenses and benefits.
The Company accounts for income taxes utilizing the asset and liability method. Under this method, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities due to a change in tax rates is recognized as income or expense in the period that includes the enactment date.
The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. In assessing the likelihood and extent that deferred tax assets will be realized, consideration is given to cumulative losses in recent years, projected future taxable income and tax planning strategies. A valuation allowance is recorded when, in the opinion of management, it is more likely than not that a portion or all of the deferred tax assets will not be realized.
The Company has federal, state and international net operating losses ("NOLs") carried forward from tax years ending before January 1, 2018 that will expire in the years 2020 through 2038. Due to U.S. tax reform, any U.S. federal income tax losses incurred for tax years beginning after December 31, 2017 can be carried forward indefinitely with no carry back available. In addition, the taxable losses generated in tax years beginning after December 31, 2017 can only offset 80% of taxable income generated in tax years beginning after December 31, 2018. After considering the scheduled reversal of deferred tax liabilities, projected future taxable income, the potential limitation on use of NOLs under Section 382 of the Internal Revenue Code of 1986, as amended (the "Code") and tax planning strategies, the Company established a valuation allowance due to the uncertainty regarding the ultimate realization of the deferred tax assets associated with its NOL carryforwards.
As a result of the Chapter 11 Proceeding, on the Plan Effective Date, the Company believes it experienced an ownership change for purposes of Section 382 of the Code because of its Restructuring Plan and that consequently its pre-change NOLs are subject to an annual limitation (See Note 14 - Chapter 11 Proceeding and Emergence for additional information, including definitions of capitalized defined terms, about the Chapter 11 Proceeding and emergence from the Chapter 11 Proceeding). The ownership change and resulting annual limitation on use of NOLs are not expected to result in
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the expiration of the Company's NOL carryforwards if it is able to generate sufficient future taxable income within the carryforward periods. However, the limitation on the amount of NOLs available to offset taxable income in a specific year may result in the payment of income taxes before all NOLs have been utilized. Additionally, a subsequent ownership change may result in further limitation on the ability to utilize existing NOLs and other tax attributes, which could cause the Company's pre-change NOL carryforwards to expire unused.
The Company recognizes the financial statement effects of a tax position when it is more-likely-than-not, based on the technical merits, that the position will be sustained upon examination. A tax position that meets the more-likely-than-not recognition threshold is measured as the largest amount of tax benefit that is greater than 50% likely of being realized upon ultimate settlement with a taxing authority. Previously recognized uncertain tax positions are reversed in the first period in which it is more-likely-than-not that the tax position would be sustained upon examination. Income tax related interest and penalties, if applicable, are recorded as a component of the provision for income tax expense. For the year ended December 31, 2018, the Company has an unrecognized income tax benefit of $6.0 million related to an increase in the estimate of the reserve for unrecognized tax benefits relating to uncertain tax positions, which is netted against net operating loss carry-forwards. The unrecognized tax benefit, or UTB, is related to a deduction for certain fees that were paid using shares of C&J common stock. These fees were associated with the January 7, 2017 plan of reorganization. The recorded unrecognized tax benefit is equal to management's estimate of the portion of the tax benefit that is less than 50% likely to be realized upon ultimate settlement with a taxing authority.
Earnings Per Share. Basic earnings (loss) per share is based on the weighted average number of common shares (“common shares”) outstanding during the applicable period and excludes shares subject to outstanding stock options, warrants and shares of restricted stock. Diluted earnings per share is computed based on the weighted average number of common shares outstanding during the period plus, when their effect is dilutive, incremental shares consisting of shares subject to outstanding stock options, warrants and restricted stock.
The following is a reconciliation of the components of the basic and diluted earnings (loss) per share calculations for the applicable periods:
A summary of securities excluded from the computation of basic and diluted earnings per share is presented below for the applicable periods:
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On January 6, 2017, the Debtors substantially consummated the Restructuring Plan and emerged from the Chapter 11 Proceeding. As part of the transactions undertaken pursuant to the Restructuring Plan, all of the existing shares of the Predecessor common equity that were used in the above earnings per share calculations of the Predecessor were canceled as of the Plan Effective Date.
Recent Accounting Pronouncements.
In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) ("ASU 2016-02"). ASU No. 2016-02 seeks to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and by disclosing key information about leasing arrangements. Unlike current U.S. GAAP, which requires only capital leases to be recognized on the balance sheet, ASU No. 2016-02 will require both operating and finance leases to be recognized on the balance sheet. Additionally, the new guidance will require disclosures to help investors and other financial statement users better understand the amount, timing, and uncertainty of cash flows arising from leases, including qualitative and quantitative requirements.
The amendments in ASU No. 2016-02 are effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years, and early application is permitted. The Company adopted this new accounting standard on January 1, 2019 using the modified retrospective approach. Under this transition method, leases existing at, or entered into after the adoption date are required to be recognized and measured. The Company has elected to use the effective date as its date of initial application, consequently prior period amounts have not been adjusted and continue to be reflected in accordance with historical accounting. The Company elected the package of practical expedients which permits them not to reassess under the new standard its prior conclusions about lease identification, lease classification and initial direct costs. The Company has also elected the practical expedient to combine the lease and non-lease components of a contract for all of its contracts, as well as the short-term lease recognition exemption.
The adoption of this standard will result in the initial recognition of approximately $25.0 million to $28.0 million of right-of-use assets and operating lease liabilities, with no related impact to consolidated stockholders' equity or net income (loss).
In June 2016, the FASB issued ASU No. 2016-13, Financial Instruments-Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments (“ASU 2016-13”), which amends U.S. GAAP by introducing a new impairment model for financial instruments that is based on expected credit losses rather than incurred credit losses. The new impairment model applies to most financial assets, including trade accounts receivable. The amendments in ASU 2016-13 are effective for interim and annual reporting periods beginning after December 15, 2019, although it may be adopted one year earlier, and requires a modified retrospective transition approach. The Company is currently evaluating the impact this standard will have on its consolidated financial statements.
In October 2016, the FASB issued ASU No. 2016-16, Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other Than Inventory ("ASU 2016-16"), which requires an entity to recognize the income tax consequences of an intra-entity asset transfer, other than an intra-entity asset transfer of inventory, when the transfer occurs. The ASU 2016-16 is effective for the interim and annual reporting periods beginning after December 15, 2017, including interim periods within those fiscal years, and early application is permitted. The Company adopted this new accounting standard on January 1, 2018, and upon adoption recognized a cumulative effect adjustment as a reduction to retained earnings of $13.2 million.
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In January 2017, the FASB issued ASU No. 2017-04, Intangibles-Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment ("ASU 2017-04"), which establishes a one-step process for testing goodwill for impairment. The ASU 2017-04 is effective for the interim and annual reporting periods beginning after December 15, 2019 and early adoption is permitted. The Company early adopted this new accounting standard on January 1, 2018, and there was no impact on its consolidated financial statements upon adoption. As part of C&J's annual impairment assessment of goodwill during the fourth quarter of 2018, the Company applied this new accounting standard and recognized an impairment charge of $146.0 million for the year ended December 31, 2018.
In February 2018, the FASB issued ASU No. 2018-02, Income Statement - Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income ("ASU 2018-02"), which allows for a reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the Tax Cuts and Jobs Act and requires certain disclosures about stranded tax effects. ASU 2018-02 is effective for the interim and annual reporting periods beginning after December 15, 2019, and early adoption is permitted. The Company is currently evaluating the impact of this standard on its consolidated financial statements.
In March 2018, the FASB issued ASU No. 2018-05, Income Taxes (Topic 740): Amendments to SEC Paragraphs Pursuant to SEC Staff Accounting Bulletin No. 118 ("ASU 2018-05"), which provides guidance on accounting for the tax effects of the Tax Cuts and Jobs Act (the "Tax Act") pursuant to Staff Accounting Bulletin No. 18, which allows companies to complete the accounting under ASC 740 within a one-year measurement period from the Tax Act enactment date. This standard is effective upon issuance. The Company adopted this new accounting standard January 1, 2018, and there was no impact on its consolidated financial statements upon adoption.
In June 2018, the FASB issued ASU No. 2018-07, Compensation-Stock Compensation (Topic 718): Improvements to Nonemployee Share-Based Payment Accounting ("ASU 2018-07"), which expands the scope of Topic 718 to include all share-based payment transactions for acquiring goods and services from nonemployees. The ASU 2018-07 is effective for the interim and annual reporting periods beginning after December 15, 2018, and early adoption is permitted. The Company adopted this new accounting standard January 1, 2019, and there was no impact on its consolidated financial statements upon adoption.
In August 2018, the FASB issued ASU No. 2018-13, Fair Value Measurement (Topic 820): Disclosure Framework-Changes to the Disclosure Requirements for Fair Value Measurement ("ASU 2018-13"), which modifies the disclosure requirements for fair value measurements by removing, modifying, or adding certain disclosures, such as additional disclosures related to the changes in unrealized gains and losses for the period included in other comprehensive income for recurring Level 3 fair value measurements held at the end of the reporting period; and the range and weighted average of significant unobservable inputs used to develop Level 3 fair value measurements. ASU 2018-13 is effective for the interim and annual reporting periods beginning after December 15, 2019, and early adoption is permitted. The Company is currently evaluating the impact of this standard on its consolidated financial statements.
In August 2018, the FASB issued ASU No. 2018-15, Intangibles - Goodwill and Other Internal-Use Software (Subtopic 350-50): Customer's Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That is a Service Contract ("ASU 2018-15"), which aligns the requirements for capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software. ASU 2018-15 is effective for the interim and annual reporting periods beginning after December 15, 2019, and early adoption is permitted. The Company is currently evaluating the impact of this standard on its consolidated financial statements.
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Note 2 - Debt
Credit Facility
The Company and certain of its subsidiaries (the “Borrowers”) entered into an asset-based revolving credit agreement with, among others, JPMorgan Chase Bank, N.A., as administrative agent (the “Agent”), on May 1, 2018 (the “Credit Facility”). This facility replaced the Prior Credit Facility discussed below.
The Credit Facility allows the Borrowers to incur revolving loans in an aggregate amount up to the lesser of (a) $400.0 million or (b) a borrowing base (the “Loan Cap”), which borrowing base is based upon the value of the Borrowers’ accounts receivable, inventory and restricted cash, subject to eligibility criteria and customary reserves which may be modified in the Agent’s permitted discretion.
The Credit Facility also provides for the issuance of letters of credit, which would further reduce borrowing capacity thereunder. The maturity date of the Credit Facility is May 1, 2023.
If at any time the amount of loans and other extensions of credit outstanding under the Credit Facility exceed the borrowing base, the Borrowers may be required, among other things, to prepay outstanding loans immediately.
The Borrowers’ obligations under the Credit Facility are secured by liens on a substantial portion of the Borrowers’ personal property, subject to certain exclusions and limitations. Upon the occurrence of certain events, additional collateral, including a portion of the Borrowers’ real properties, may also be required to be pledged. Each of the Borrowers is jointly and severally liable for the obligations of the other Borrowers under the Credit Facility.
At the Borrowers’ election, interest on borrowings under the Credit Facility will be determined by reference to either LIBOR plus an applicable margin of between 1.5% and 2.0% or an “alternate base rate” plus an applicable margin of between 0.5% and 1.0%, in each case based on the Company’s total leverage ratio. Interest will be payable quarterly for loans bearing interest based on the alternative base rate and on the last day of the interest period applicable to LIBOR-based loans and, in the case of an interest period longer than three months, quarterly, upon any prepayment and at final maturity. The Borrowers will also be required to pay a fee on the unused portion of the Credit Facility equal to (i) 0.5% per annum if average utilization is less than or equal to 25% or (ii) 0.375% per annum if average utilization is greater than 25%, in each case payable quarterly in arrears to the Agent.
The Credit Facility contains covenants that limit the Borrowers’ ability to incur additional indebtedness, grant liens, make loans, make acquisitions or investments, make distributions, merge into or consolidate with other persons, or engage in certain asset dispositions.
The Credit Facility also contains a financial covenant which requires the Company to maintain a monthly minimum fixed charge coverage ratio of 1.0:1.0 upon the occurrence of an event of default or on any date upon which the excess availability is less than the greater of (x) 12.5% of the Loan Cap and (y) $30.0 million. The fixed charge coverage ratio is generally defined in the Credit Facility as the ratio of (i) EBITDA minus certain capital expenditures and cash taxes paid to (ii) the sum of cash interest expenses, scheduled principal payments on borrowed money and certain distributions.
As of December 31, 2018, the Company was in compliance with all financial covenants of the Credit Facility.
Prior Credit Facility
On January 6, 2017, in connection with the emergence from bankruptcy, the Company entered into a revolving credit and security agreement with PNC Bank, National Association, as administrative agent, which was subsequently amended and restated on May 4, 2017 (the “Prior Credit Facility”). The Prior Credit Facility was canceled and discharged on May 1, 2018.
The Prior Credit Facility allowed the Company and certain of its subsidiaries (the “Prior Borrowers”), to incur revolving loans in an aggregate amount up to the lesser of $200.0 million and a borrowing base, which borrowing base was based upon the value of the Prior Borrowers’ accounts receivable and inventory, subject to eligibility criteria and customary reserves which may have been modified in the Agent’s permitted discretion. The Prior Credit Facility also provided for the issuance of letters of credit, which would further reduce borrowing capacity thereunder. The maturity date of the Prior Credit Facility was May 4, 2022.
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If at any time the amount of loans and other extensions of credit outstanding under the Prior Credit Facility exceeded the borrowing base, the Prior Borrowers may have been required, among other things, to prepay outstanding loans immediately.
The Prior Borrowers’ obligations under the Prior Credit Facility were secured by liens on a substantial portion of the Prior Borrowers’ personal property, subject to certain exclusions and limitations. Upon the occurrence of certain events, additional collateral, including a portion of the Prior Borrowers’ real properties, may also have been required to be pledged. Each of the Prior Borrowers was jointly and severally liable for the obligations of the other Prior Borrowers under the Prior Credit Facility.
At the Prior Borrowers’ election, interest on borrowings under the Prior Credit Facility would have been determined by reference to either LIBOR plus an applicable margin of 2.0% or an “alternate base rate” plus an applicable margin of 1.0%. Beginning after the fiscal month ending on or about September 30, 2017, these margins were subject to a monthly step-up of 0.25% in the event that average excess availability under the Prior Credit Facility was less than 37.5% of the total commitment, and a monthly step-down of 0.25% in the event that average excess availability under the Prior Credit Facility was equal to or greater than 62.5% of the total commitment. Interest was payable quarterly for loans bearing interest based on the alternative base rate and on the last day of the interest period applicable to LIBOR-based loans. The Prior Borrowers were also required to pay a fee on the unused portion of the Prior Credit Facility equal to (i) 0.75% in the event that utilization was less than 25% of the total commitment, (ii) 0.50% in the event utilization was equal to or greater than 25% of the total commitment but less than 50% of the total commitment and (iii) 0.375% in the event that utilization was equal to or greater than 50% of the total commitment.
The Prior Credit Facility contained covenants that limited the Prior Borrowers’ ability to incur additional indebtedness, grant liens, make loans or investments, make distributions, merge into or consolidate with other persons, make capital expenditures or engage in certain asset dispositions including a sale of all or substantially all of the Company’s assets.
The Prior Credit Facility also contained a financial covenant that required the Company to maintain a monthly minimum fixed charge coverage ratio of 1.0:1.0 if, as of any month-end, liquidity was less than $40.0 million.
The fixed charge coverage ratio was generally defined in the Prior Credit Facility as the ratio of (i) EBITDA minus certain capital expenditures and cash taxes paid to (ii) the sum of cash interest expenses, scheduled principal payments on borrowed money and certain distributions.
In connection with the cancellation and discharge of the Prior Credit Facility, the Company accelerated the amortization of $1.5 million in deferred financing costs during the second quarter of 2018.
Capital Lease Obligations
In October 2016, the Company entered into amended lease agreements related to the Company’s corporate headquarters and its R&T facility, both originally entered into during 2013 and accounted for as capital leases. The Company determined that both amended lease agreements qualified as a new operating lease under ASC 840 - Leases, which resulted in accounting for the amended leases as a sale-leaseback pursuant to the requirements of ASC 840. The conversion from capital lease to operating lease accounting treatment resulted in the deferral of $6.3 million of gain. As a result of the adoption of Fresh Start Accounting, the Company accelerated the recognition of the deferred gain balance through the Fresh Start adjustments. As of December 31, 2018, the Company had no capital lease obligations.
Interest Expense
For the years ended December 31, 2018, 2017 and 2016, interest expense consisted of the following:
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As of June 30, 2016, based on the negotiations between the Company and the lenders, it became evident that the restructuring of the Company's capital structure would not include a restructuring of the Company's Revolving Credit Facility, the Five-Year Term Loans and the Seven-Year Term Loans, and these debt obligations, as demand obligations, would not be paid in the ordinary course of business over the term of these loans. As a result, during the second quarter of 2016, the Company accelerated the amortization of the associated original issue discount and deferred financing costs, fully amortizing these amounts as of June 30, 2016. In addition, the Company did not accrue interest that it believed was not probable of being treated as an allowed claim in the Chapter 11 Proceeding. For the year ended December 31, 2016, the Company did not accrue interest totaling $60.5 million under the Credit Agreement subsequent to the Petition Date.
Note 3 - Goodwill and Other Intangible Assets
On November 30, 2017, the Company acquired all of the outstanding equity interests of O-Tex Holdings, Inc., and its operating subsidiaries ("O-Tex"). See Note 10 - Acquisitions for further discussion on the O-Tex transaction. As of December 31, 2018, all off the goodwill recorded on the Company's consolidated balance sheet was related to the O-Tex transaction and was recorded within the WC&I reporting unit.
The Company early adopted ASU No. 2017-04, which establishes a one-step process for testing goodwill for impairment. During December 2018, and prior to the completion of the Company's annual test for goodwill impairment as of October 31, 2018, significant volatility in the equity markets and overall decrease in commodity prices led to a decline in the Company's market capitalization. This decline in market capitalization, when compared to C&J's book value of equity, was significant enough to be considered a triggering event, leading to a test for goodwill impairment as of December 31, 2018. The Company chose to bypass a qualitative approach and instead opted to employ the detailed Step 1 impairment testing methodologies discussed below.
Income approach
The income approach impairment testing methodology is based on a discounted cash flow model, which utilizes present values of cash flows to estimate fair value. For the WC&I reporting unit, the future cash flows were projected based on estimates of projected revenue growth, unit count, utilization, pricing, gross profit rates, SG&A rates, working capital fluctuations and capital expenditures. Forecasted cash flows took into account known market conditions as of December 31, 2018, and management’s anticipated business outlook.
A terminal period was used to reflect an estimate of stable, perpetual growth. The terminal period reflects a terminal growth rate of 2.5%.
The future cash flows were discounted using a market-participant risk-adjusted weighted average cost of capital (“WACC”) of 16.0%. These assumptions were derived from unobservable inputs and reflect management’s judgments and assumptions.
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Market approach
The market approach impairment testing methodology is based upon the guideline public company method and the guideline transaction method. The application of the guideline public company method was based upon selected public companies operating within the same industry as the Company. Based on this set of comparable competitor data, price-to-earnings multiples were derived, and a range of price-to-earnings multiples was determined for the WC&I reporting unit. The selected market multiple for the guideline public company method was 4.25x for the WC&I reporting unit. The application of the guideline transaction method was based upon valuation multiples derived from actual transactions for comparable companies. Based on this, valuation multiples are derived from historical data of selected transactions, then evaluated and adjusted, if necessary, based on the strengths and weaknesses of the subject company relative to the derived market data. The selected market multiple for the guideline transaction method was 4.0x for the WC&I reporting unit.
The fair value determined under the market approach is sensitive to these market multiples, and a decline in any of the multiples could reduce the estimated fair value of the reporting unit below its carrying value. Earnings estimates were derived from unobservable inputs that require significant estimates, judgments and assumptions as described in the income approach.
The estimated fair value determined under the income approach was consistent with the estimated fair value determined under the market approach. The concluded fair value for the WC&I reporting unit consisted of a weighted average, with a 60.0% weight under the income approach and a 40.0% weight under the market approach. The concluded fair values for the Completion Services and Well Support Services reporting units were each derived using the market approach. As a way to validate the estimated reporting units' fair values, the total market capitalization of the Company was compared to the total estimated fair value of all reporting units, and an implied control premium was derived. Market data in support of the implied control premium was used in this reconciliation to corroborate the estimated reporting unit fair values.
The results of the Step 1 impairment testing for the WC&I reporting unit concluded that the fair value of the reporting unit was below its carrying value by an amount slightly in excess of the goodwill balance. As a result, the Company recognized impairment expense of $146.0 million during 2018, representing the entire balance of goodwill.
During the first quarter of 2016, utilization and commodity price levels continued to fall towards unprecedented levels and the resulting negative impact on the Company’s results of operations, coupled with the sustained decrease in the Company’s stock price, were deemed triggering events that led to an interim period test for goodwill impairment. The Company chose to bypass a qualitative approach and instead opted to employ the detailed Step 1 impairment testing methodologies discussed below.
Income approach
The income approach impairment testing methodology is based on a discounted cash flow model, which utilizes present values of cash flows to estimate fair value. For the Completion Services and Well Support Services reporting units, the future cash flows were projected based on estimates of projected revenue growth, fleet and rig count, utilization, gross profit rates, SG&A rates, working capital fluctuations, and capital expenditures. For the Other Services reporting unit, the future cash flows were projected based primarily on estimates of future demand for manufactured and refurbished equipment as well as parts and service, gross profit rates, SG&A rates, working capital fluctuations, and capital expenditures. Forecasted cash flows for the three reporting units took into account known market conditions as of March 31, 2016, and management’s anticipated business outlook, both of which had been impacted by the sustained decline in commodity prices.
A terminal period was used to reflect an estimate of stable, perpetual growth. The terminal period reflects a terminal growth rate of 2.5% for all three reporting units, including an estimated inflation factor.
The future cash flows were discounted using a market-participant risk-adjusted weighted average cost of capital (“WACC”) of 14.5% for Completion Services, 14.0% for Well Support Services, and 16.0% for Other Services reporting units. These assumptions were derived from unobservable inputs and reflect management’s judgments and assumptions.
Market approach
The market approach impairment testing methodology is based upon the guideline public company method. The application of the guideline public company method was based upon selected public companies operating within the same
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industry as the Company. Based on this set of comparable competitor data, price-to-earnings multiples were derived, and a range of price-to-earnings multiples was determined for each reporting unit. Selected market multiples were 10.6x for Completion Services, 10.5x for Well Support Services and 11.0x for Other Services reporting units.
The fair value determined under the market approach is sensitive to these market multiples, and a decline in any of the multiples could reduce the estimated fair value of any of the three reporting units below their respective carrying values. Earnings estimates were derived from unobservable inputs that require significant estimates, judgments and assumptions as described in the income approach.
The estimated fair value determined under the income approach was consistent with the estimated fair value determined under the market approach. The concluded fair value for the Completion Services and Well Support Services reporting units consisted of a weighted average, with an 80.0% weight under the income approach and a 20.0% weight under the market approach. The concluded fair value for the Other Services reporting unit consisted of a weighted average with a 50.0% weight under the income approach and a 50.0% weight under the market approach.
The results of the Step 1 impairment testing indicated potential impairment in the Well Support Services reporting unit. The goodwill associated with both the Completion Services and Other Services reporting units was completely impaired during the third quarter of 2015. As a way to validate the estimated reporting unit fair values, the total market capitalization of the Company was compared to the total estimated fair value of all reporting units, and an implied control premium was derived. Market data in support of the implied control premium was used in this reconciliation to corroborate the estimated reporting unit fair values.
Step 2 of the goodwill impairment testing for the Well Support Services reporting units was performed during the first quarter of 2016, and the results concluded that there was no value remaining to be allocated to the goodwill associated with this reporting unit. As a result, the Company recognized impairment expense of $314.3 million during 2016.
As of December 31, 2018, there was no goodwill remaining across the Company's three reporting units. The changes in the carrying amount of goodwill for the years ended December 31, 2018 and 2017 are as follows:
Indefinite-Lived Intangible Assets
As of December 31, 2016, the Company had approximately $6.0 million of intangible assets with indefinite useful lives, which were subject to annual impairment tests or more frequently if events or circumstances indicate the carrying amount may not be recoverable.
The Company’s intangible assets associated with intellectual property, research and development (“IPR&D”) consisted of technology that was still in the testing phase; however, given the continued market downturn management made the decision to postpone these projects. Based on the Company's evaluation, it was determined that the IPR&D carry value of $6.0 million was impaired and written down to zero as of December 31, 2016.
As of December 31, 2018, the balance of indefinite-lived intangible assets was zero.
Definite-Lived Intangible Assets
The Company reviews definite-lived intangible assets, along with PP&E, for impairment when a triggering event indicates that the asset may have a net book value in excess of recoverable value.
C&J ENERGY SERVICES, INC. AND SUBSIDIARIES
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During the fourth quarter of 2018, in connection with the Company's test for goodwill, the Company deemed the deficit of the Well Support Services reporting unit's book value of equity over its concluded fair value of equity to be a triggering event that provided indicators that its definite-lived intangible assets may be impaired for the asset groups within the reporting unit. Recoverability testing was performed for the well support services asset group and yielded an estimated undiscounted net cash flow that was in excess of the carrying amount of the related assets, and no impairment was indicated.
During 2016, management determined the sustained low commodity price levels coupled with the sustained decrease in the Company’s share price were deemed triggering events that provided indicators that its definite-lived intangible assets may be impaired. The Company performed a recoverability test on all of its definite-lived intangible assets and PP&E by comparing the estimated future net undiscounted cash flows expected to be generated from the use of these assets to the carrying amounts of the assets for recoverability. If the estimated undiscounted cash flows exceed the carrying amount of the assets, an impairment does not exist, and a loss will not be recognized. If the undiscounted cash flows are less than the carrying amount of the assets, the assets are not recoverable, and the amount of impairment must be determined by fair valuing the assets.
Recoverability testing through June 30, 2016 resulted in the determination that certain intangible assets associated with the Company’s wireline and artificial lift lines of business were not recoverable. The fair value of the wireline and artificial lift assets was determined to be approximately $38.2 million and zero, respectively, resulting in impairment expense of $50.4 million and $4.6 million, respectively. For the year ended December 31, 2016, the Company recorded $55.0 million of impairment expense, as the intangible assets assessed were determined not to be recoverable.
The changes in the carrying amounts of other intangible assets for the year ended December 31, 2018 are as follows:
Amortization expense for the years ended December 31, 2018, 2017 and 2016 totaled $8.8 million, $4.2 million and $10.8 million, respectively.
Estimated amortization expense for each of the next five years and thereafter is as follows:
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Note 4 - Income Taxes
On December 22, 2017, the Tax Cuts and Jobs Act ("U.S. Tax Reform") was enacted by the U.S. federal government. The legislation significantly changed U.S. income tax law, by among other things, lowering the federal corporate income tax rate from 35% to 21%, effective January 1, 2018, implementing a territorial tax system and imposing a one-time toll charge on deemed repatriated earnings of foreign subsidiaries. In addition, there are many new provisions, including changes to expensing of qualified tangible property, the deductions for executive compensation and interest expense, a global intangible low-tax income provision, the base erosion anti-abuse tax, and a deduction for foreign-derived intangible income. The Company's consolidated financial statements for the year ended December 31, 2017 were impacted by the corporate income tax rate reduction going from 35% to 21%. This rate reduction required the revaluation of the Company's deferred tax assets and liabilities as of the U.S. Tax Reform enactment date. The revaluation reflects an assumption that the new federal corporate income tax rate will remain in place for the years in which temporary differences are expected to reverse. The Company recorded a reduction to the provisional tax benefit for the impact of the U.S. Tax Reform of approximately $160.0 million, with a corresponding reduction in the recorded valuation allowance of approximately $162.3 million. The provisional tax benefit is primarily comprised of the remeasurement of U.S. federal deferred tax assets and liabilities resulting from the permanent reduction of the statutory corporate tax rate to 21% from 35%, after taking into account any mandatory one-time tax on the accumulated earnings of its foreign subsidiaries. The amount of this one-time tax was not material. In 2018, C&J completed its determination of the accounting implications of U.S. Tax Reform and determined there were no additional material adjustments required.
The provision for income taxes consisted of the following:
The following table reconciles the statutory tax rates to the Company’s effective tax rate:
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The Company’s deferred tax assets and liabilities consisted of the following:
The Company has Federal NOLs of $1.3 billion of which approximately $1.1 billion of U.S. federal net operating loss carryforwards (“NOLs”) which, if not utilized, will begin to expire in the year 2035. The Company also generated a U.S. federal NOL carryforward of $209.9 million which can be carried forward indefinitely. The Company has state NOLs of approximately $609.4 million which, if not utilized, will expire in various years between 2020 and 2038. Additionally, the Company has approximately $21.1 million of NOLs in other jurisdictions which, if not utilized, will expire in various years between 2020 and 2038. As of December 31, 2018, the Company has recorded a net deferred tax asset of approximately $302.0 million relating to NOLs, and an offsetting valuation allowance has been provided for these NOLs due to uncertainty regarding the ultimate realization of the deferred tax assets associated with the NOL carryforwards prior to expiration. Additionally, the Company has foreign operating loss carryforwards of approximately $920.6 million for which the realization of a tax benefit is considered remote. Due to the remote likelihood of utilizing these foreign NOLs, neither the deferred tax asset nor the offsetting valuation allowance has been recorded, and neither is presented in the table above.
The Company's ability to utilize its U.S. NOL carryforwards to offset future taxable income and to reduce U.S. federal income tax liability is subject to certain requirements and restrictions. In general, under Section 382 of the Code, a corporation that undergoes an “ownership change” is subject to limitations on its ability to utilize its pre-change NOLs to offset future taxable income. An ownership change generally occurs if one or more shareholders (or groups of shareholders) who are each deemed to own at least 5% of the Company's stock have aggregate increases in their ownership of such stock of more than 50 percentage points over such stockholders’ lowest ownership percentage during the testing period (generally a rolling three year period). The Company believes it experienced an ownership change in January 2017 as a result of the implementation of the Restructuring Plan. As a result, the Company's pre-change NOLs are subject to limitation under Section 382 of the Code. Such limitation may cause U.S. federal income taxes to be paid earlier than otherwise would be paid if such limitation were not in effect. The Company does not believe that the ownership change created a restriction, which, by itself, could cause its pre-change NOLs to expire unused. As of December 31, 2018, management’s assessment that a full valuation allowance is appropriate due to uncertainty about ultimate realization of the deferred tax assets was determined before consideration of a Section 382 limitation. Similar rules and limitations may apply for state income tax purposes. The Company remains subject to ongoing testing for future ownership changes based on shareholder ownership that may create a more restrictive Section 382 limitation on the NOLs in subsequent reporting periods.
The Company’s U.S. federal income tax returns for the tax years 2015 through 2017 remain open to examination by the Internal Revenue Service under the applicable U.S. federal statute of limitations provisions. The various states in which the Company is subject to income tax are generally open to examination for the tax years after 2014.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
A reconciliation of unrecognized tax benefit balances is as follows:
As of December 31, 2018, the Company had an unrecognized tax benefit balance of $6.0 million related to a deduction for certain fees that were paid using shares of C&J common stock. These fees were associated with the January 7, 2017 plan of reorganization. The recorded unrecognized tax benefit is equal to management's estimate of the portion of the tax benefit that is less than 50% likely to be realized upon ultimate settlement with a taxing authority. The unrecognized tax benefit is reflected in C&J's consolidated financial statements as a reduction to its net operating loss carryover and associated deferred tax asset before the offsetting impact from the valuation allowance. Given the Company's existing net deferred tax asset and valuation allowance, the uncertain tax benefit had not impact to C&J's consolidated financial statements.
The Company classifies interest and penalties within the provision for income taxes. The Company had no interest and penalties in the provision for income taxes for each of the years ended December 31, 2018, 2017 and 2016.
Note 5 - Stockholders' Equity
Stock Repurchase
On July 31, 2018, C&J’s Board of Directors approved a stock repurchase program authorizing the repurchase of up to $150.0 million of the Company’s common stock over a twelve month period starting August 1, 2018. Repurchases may commence or be suspended at any time without notice. The program does not obligate the Company to purchase a specified number of shares of common stock during the period or at all and may be modified or suspended at any time at the Company’s discretion.
During 2018, C&J executed $40.4 million of total stock repurchases at an average price of $16.55 per share, representing a total of approximately 2.4 million shares of the Company's common stock.
Share-Based Compensation
Pursuant to the Restructuring Plan, the Company adopted the C&J Energy Services, Inc. 2017 Management Incentive Plan (as amended from time to time, the “MIP”) as of the Plan Effective Date.
The MIP provides for the grant of share-based awards to the Company’s employees, consultants and non-employee directors. The following types of awards are available for issuance under the MIP: incentive stock options and nonqualified stock options, share appreciation rights, restricted shares, restricted share units, dividend equivalent rights, performance stock, share awards, other share-based awards and substitute awards. As of December 31, 2018, only nonqualified stock options, restricted shares, performance stock and restricted share units have been awarded under the MIP.
A total of approximately 8.0 million shares of common stock were originally authorized and approved for issuance under the MIP. The number of shares of common stock available for issuance under the MIP is subject to adjustment in the event of a reclassification, recapitalization, merger, consolidation, reorganization, spin-off, split-up, issuance of warrants, rights or debentures, share dividend, share split or reverse share split, cash dividend, property dividend, combination or exchange of shares, repurchase of shares, change in corporate structure or any similar corporate event or transaction. The number of shares of common stock available for issuance may also increase due to the termination of an award granted under the MIP or by expiration, forfeiture, cancellation or otherwise without the issuance of the common stock.
Restricted Share Units
Restricted Share Units ("RSU's") represent the right to receive shares of common stock or the cash value of one share of common stock in the future at the discretion of the Company's compensation committee. The value of the Company’s
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
outstanding RSU's is based on the closing price of the Company’s common stock on the NYSE on the date of grant. RSU's granted that are intended to be settled in cash ("Cash RSU's") are classified as liabilities and are remeasured at each reporting date until settlement. The Company does not have any outstanding Cash RSU's.
For the year ended December 31, 2018, the Company granted approximately 0.9 million RSU's to employees under the MIP, at a fair market value of $14.59 per RSU. RSU awards granted to employees during 2018 will vest over three years of continuous service from the grant date, with one-third vesting on each of the first, second and third anniversaries.
A summary of the status and changes during the year ended December 31, 2018 of the Company’s non-vested RSU's is presented below:
As of December 31, 2018, the Company had approximately $12.2 million in unrecognized compensation cost related to RSU's to be expensed over a weighted average remaining service period of 2.95 years.
Stock Options
The fair value of each option award granted under the MIP is estimated on the date of grant using the Black-Scholes option-pricing model. Determination of the fair value was a matter of judgment and often involved the use of significant estimates and assumptions. Additionally, due to the Company’s lack of historical volume of option activity, the expected term of options granted was derived using the “plain vanilla” method. Expected volatilities were based on comparable public company data, with consideration given to the Company’s limited historical data. The Company makes estimates with respect to employee termination and forfeiture rates of the options within the valuation model. The risk-free rate is based on the approximate U.S. Treasury yield rate in effect at the time of grant. During the year ended December 31, 2017, approximately 0.4 million nonqualified stock options were granted under the MIP to certain of the Company's executive officers at a fair market value ranging from $16.55 to $22.19 per nonqualified stock option. Stock options granted during the first quarter of 2017 will expire on the tenth anniversary of the grant date and will vest over three years of continuous service from the grant date, with 34% vesting immediately upon the grant date, and 22% on each of the first, second and third anniversaries of the grant date. Stock options granted during the fourth quarter of 2017 will expire on the tenth anniversary of the grant date and will vest over three years of continuous service from the grant date, with one-third vesting on each of the first, second and third anniversaries of the grant date. No stock options were granted by the Company during 2018.
The following table presents the assumptions used in determining the fair value of option awards granted during the year ended December 31, 2017.
The weighted average grant date fair value of options granted for the year ended December 31, 2017 was $20.66.
A summary of the Company’s stock option activity for the year ended December 31, 2018 is presented below.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
As of December 31, 2018, the Company had approximately $2.1 million in unrecognized compensation cost related to outstanding stock options to be expensed over a weighted average remaining service period of 1.5 years.
Restricted Stock
The value of the Company’s outstanding restricted stock is based on the closing price of the Company’s common stock on the NYSE on the date of grant. During 2018, approximately 0.1 million shares of restricted stock were granted to employees and non-employee directors under the MIP, at fair market values ranging from $15.00 to $23.60 per share of restricted stock. Restricted stock awards granted to employees during 2018 will vest over three years of continuous service from the grant date, with one-third vesting on each of the first, second and third anniversaries. Restricted stock awards granted to non-employee directors will vest in full on the first anniversary of the date of grant, subject to each director's continued service. During the year ended December 31, 2017, approximately 1.7 million shares of restricted stock were granted to employees and non-employee directors under the MIP, at fair market values ranging from $31.52 to $44.90 per share of restricted stock. Restricted stock awards granted to employees during the first quarter of 2017 will vest over three years of continuous service from the grant date, with 34% having vested immediately upon the grant date, and 22% on each of the first, second and third anniversaries of the grant date. Restricted stock awards granted to employees during the fourth quarter of 2017 will vest over three years of continuous service from the grant date, with one-third vesting on each of the first, second and third anniversaries. Restricted stock awards granted to non-employee directors during the fourth quarter of 2017 vested in full on the first anniversary date of the grant.
To the extent permitted by law, the recipient of an award of restricted stock will generally have most of the rights of a stockholder with respect to the underlying common stock, including the right to vote the common stock and to receive all dividends or other distributions made with respect to the common stock. Dividends on restricted stock will be deferred until the lapsing of the restrictions imposed on the stock and will be held by the Company for the account of the recipient (either in cash or to be reinvested in restricted stock) until such time. Payment of the deferred dividends and accrued interest, if any, shall be made upon the lapsing of restrictions on the restricted stock, and any dividends deferred in respect of any restricted stock shall be forfeited upon the forfeiture of such restricted stock. As of December 31, 2018, the Company had not issued any dividends.
A summary of the status and changes during the year ended December 31, 2018 of the Company’s shares of non-vested restricted stock is presented below:
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
As of December 31, 2018, the Company had approximately $21.1 million in unrecognized compensation cost related to restricted stock to be expensed over a weighted average remaining service period of 1.6 years.
Performance Stock
During the fourth quarter of 2018, the Company granted approximately 0.3 million shares of performance stock under the MIP to certain of the Company's executive officers at a fair market value of approximately $17.99 per share. During the fourth quarter of 2017, the Company granted approximately 0.1 million shares of performance stock under the MIP to certain of the Company's executive officers at a fair market value of $37.20 per share of restricted stock. The performance stock cliff vests at the end of a three year performance period, and the participants may earn between 0% and 200% of the target number of the shares granted based on actual stock price performance upon comparison to a peer group. The vesting of these awards is subject to each employee's continued employment. The Company values equity awards with market conditions at the grant date using a Monte Carlo simulation model which simulates many possible future outcomes.
The following table presents the assumptions used in determining the fair value of the performance stock granted during the years ended December 31, 2018 and 2017.
A summary of the status and changes during the year ended December 31, 2018 of the Company’s performance stock is presented below:
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
As of December 31, 2018, the Company had approximately $7.5 million in unrecognized compensation cost related to performance stock to be expensed over a weighted average remaining service period of 2.7 years.
Share-based compensation expense was $18.8 million and $23.4 million for the years ended December 31, 2018 and 2017, respectively, and is included in selling, general and administrative expenses, direct costs and research and development on the consolidated statements of operations. Due to the valuation allowance that has been provided for NOLs as a result of the uncertainty regarding the ultimate realization of the Company's deferred tax assets, there was no income tax benefit recognized in the consolidated statements of operations in connection with share-based compensation expense for the years ended December 31, 2018 and 2017.
Predecessor Equity Plans
In connection with the Nabors Merger, the Company approved and adopted the C&J Energy Services 2015 Long Term Incentive Plan (the “2015 LTIP”), effective as of March 23, 2015, contingent upon the consummation of the Nabors Merger. The 2015 LTIP served as an assumption of the Old C&J 2012 Long-Term Incentive Plan, (the “2012 LTIP”), with certain non-material revisions made and no increase in the number of shares remaining available for issuance under the 2012 LTIP. Prior to the adoption of the 2015 LTIP, all share-based awards granted to Old C&J employees, consultants and non-employee directors were granted under the 2012 LTIP and, following the 2015 LTIP’s adoption, no further awards were granted under the 2012 LTIP. Awards that were previously outstanding under the 2012 LTIP would have continued to remain outstanding under the 2015 LTIP, as adjusted to reflect the Nabors Merger. At the closing of the Nabors Merger, restricted shares and stock option awards were granted under the 2015 LTIP to certain employees of the C&P Business and approximately 0.4 million C&J common shares underlying those awards were deemed part of the consideration paid to Nabors for the Nabors Merger.
The 2015 LTIP provided for the grant of share-based awards to the Company’s employees, consultants and non-employee directors. The following types of awards were available for issuance under the 2015 LTIP: incentive stock options and nonqualified stock options, share appreciation rights, restricted shares, restricted share units, dividend equivalent rights, performance stock and share awards. As of December 31, 2016, only nonqualified stock options and restricted shares were awarded under the 2015 LTIP and 2012 LTIP. No grants were issued during the year ended December 31, 2016.
Approximately 11.3 million shares were available for issuance under the 2015 LTIP as of December 31, 2016. The number of common shares available for issuance under the 2015 LTIP was subject to adjustment in the event of a reclassification, recapitalization, merger, consolidation, reorganization, spin-off, split-up, issuance of warrants, rights or debentures, share dividend, share split or reverse share split, cash dividend, property dividend, combination or exchange of shares, repurchase of shares, change in corporate structure or any similar corporate event or transaction.
A total of 4.3 million common shares were originally authorized and approved for issuance under the 2012 LTIP and on June 4, 2015, the shareholders of the Company approved the First Amendment to the 2015 LTIP, which increased the number of common shares that may be issued under the 2015 LTIP by approximately 3.6 million shares. The shareholders of the Company approved the Second Amendment to the 2015 LTIP in February 2016, which increased the number of common shares that may be issued by approximately 6.0 million shares. Including the add-back of approximately 0.9 million restricted shares and 0.7 million options canceled or expired under the 2012 LTIP and 2015 LTIP during 2016, approximately 11.3 million shares were available for issuance under the 2015 LTIP as of December 31, 2016. The number of common shares available for issuance under the 2015 LTIP was subject to adjustment in the event of a reclassification, recapitalization, merger, consolidation, reorganization, spin-off, split-up, issuance of warrants, rights or debentures, share dividend, share split or reverse share split, cash dividend, property dividend, combination or exchange of shares, repurchase of shares, change in corporate
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
structure or any similar corporate event or transaction. The number of common shares available for issuance were also subject to increase due to the termination of an award granted under the 2015 LTIP, the 2012 LTIP or the Prior Plans (as defined below), by expiration, forfeiture, cancellation or otherwise without the issuance of the common shares. The 2015 LTIP was terminated as described in Note 14 - Chapter 11 Proceeding and Emergence, pursuant to the Restructuring Plan, the liquidation of C&J Energy Services Ltd. was completed under the laws of Bermuda, and all of the existing shares of the Predecessor's common equity were canceled as of the Effective Date. Also, on the Effective Date, the Successor issued the New Warrants to the holders of the canceled Predecessor common shares, provided that such class of holders voted to accept the Restructuring Plan.
Stock Options
The fair value of each option award granted under the 2015 LTIP, the 2012 LTIP and the Prior Plans was estimated on the date of grant using the Black-Scholes option-pricing model. Option awards were generally granted with an exercise price equal to the market price of the Company’s common shares on the grant date. Due to the Company’s lack of historical volume of option activity, the expected term of options granted was derived using the “plain vanilla” method. In addition, expected volatilities were based on comparable public company data, with consideration given to the Company’s limited historical data. The Company made estimates with respect to employee termination and forfeiture rates of the options within the valuation model. The risk-free rate was based on the approximate U.S. Treasury yield rate in effect at the time of grant. No options were granted during the year ended December 31, 2016.
A summary of the Company’s stock option activity through December 31, 2016 is presented below.
Restricted Shares
Historically, restricted shares were valued based on the closing price of the Company’s common shares on the NYSE on the date of grant. During the year ended December 31, 2016 there were no restricted shares granted to employees and non-employee directors under the 2015 LTIP.
To the extent permitted by law, the recipient of an award of restricted shares had all of the rights of a shareholder with respect to the underlying common shares, including the right to vote the common shares and to receive all dividends or other distributions made with respect to the common shares. Dividends on restricted shares would have been deferred until the lapsing of the restrictions imposed on the shares and would be held by the Company for the account of the recipient (either in cash or to be reinvested in restricted shares) until such time. Payment of the deferred dividends and accrued interest, if any, would have been made upon the lapsing of restrictions on the restricted shares, and any dividends deferred in respect of any restricted shares would be forfeited upon the forfeiture of such restricted shares. As of December 31, 2016, the Company did not issue any dividends
A summary of the status and changes during the year ended December 31, 2016 of the Company’s shares of non-vested restricted shares is presented below:
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
As of December 31, 2016, there was $8.9 million of total unrecognized compensation cost related to restricted shares. That cost was expected to be recognized over a weighted-average period of 1.42 years.
As of December 31, 2016, the Company had 5.3 million stock options and restricted shares outstanding to employees and non-employee directors, 0.3 million of which were issued under the 2006 Plan, 3.9 million were issued under the 2010 Plan, 0.2 million were issued under the 2012 Plan and the remaining 0.9 million were issued under the 2015 Plan.
Share-based compensation expense was $17.7 million for the year ended December 31, 2016, and is included in selling, general and administrative expenses, direct costs and research and development on the consolidated statements of operations. The total income tax benefit recognized in the consolidated statements of operations in connection with share-based compensation expense was approximately $6.2 million for the year ended December 31, 2016.
Note 6 - Related Party Transactions
The Company obtained support services from vendors which are affiliated with one of its employees. For the year ended December 31, 2018, purchases from these vendors totaled $0.2 million. There were no amounts due to these vendors as of December 31, 2018. Purchases from these vendors for the year ended December 31, 2017 totaled $0.9 million and amounts due to these vendors were $0.3 million. There were no purchases from these vendors for the years ended December 31, 2016.
The Company obtained support services from Nabors Corporate Services, Inc., on a transitional basis, for the processing of payroll, benefits and certain administrative services of the C&P business in normal course following the completion of the Nabors Merger. There were no obligations incurred to Nabors Corporate Services during 2017. During 2016 and prior to the Confirmation Date, the Company, the Official Committee of Unsecured Creditors of CJ Holding Co, the Steering Committee of Lenders under the Credit Agreement and the DIP Facility, and Nabors entered into a mediated settlement agreement that was subsequently approved by the Bankruptcy Court whereby, among other things, Nabors was awarded two allowed proofs of claim totaling $13.3 million. As of December 31, 2016, the allowed proofs of claim were included in liabilities subject to compromise on the consolidated balance sheet. As a result of the Company's emergence from the Chapter 11 Proceeding and the cancellation of the Predecessor common shares, Nabors Corporate Services is no longer considered a related party.
The Company leased certain properties from Nabors, and Nabors leased certain properties from the Company. For the year ended December 31, 2016, the Company incurred obligations to Nabors of approximately $0.6 million under the leases, and Nabors incurred obligations to C&J of approximately $0.5 million and $0.1 million under the leases for each of the years ended December 31, 2017 and 2016. Amounts payable to Nabors at December 31, 2017 were $0.9 million. As a result of the Company's emergence from the Chapter 11 Proceeding and the cancellation of the Predecessor common shares, Nabors Corporate Services is no longer considered a related party.
The Company provided certain services to Shehtah Nabors LP, a Nabors partnership with a third-party, pursuant to a Management Agreement and a Cash Flow Sharing Agreement (collectively, “Shehtah Agreements”). Nabors incurred obligations to the Company of approximately $1.8 million under the Shehtah Agreements during 2016. There were no amounts due to the Company under the Shehtah Agreements at December 31, 2016. The Company did not provide services to Shehtah during 2017. As a result of the Company's emergence from the Chapter 11 Proceeding and the cancellation of the Predecessor common shares, Nabors Corporate Services is no longer considered a related party.
The Company utilizes the services of certain saltwater disposal wells owned by Pyote Water Solutions, LLC, Pyote Water Systems, LLC, Pyote Water Systems II, LLC and Pyote Water Systems III, LLC (together “Pyote”) used in the disposal of certain fluids associated with oil and gas production. A former member of the Company's Board of Directors, who served from
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
March 24, 2015 until December 16, 2016, holds the position of President and Chief Manager of Pyote and serves as Chairman of the Board of Governors of Pyote. Amounts invoiced from Pyote totaled approximately $0.8 million for the year ended December 31, 2016. Amounts payable to this vendor at December 31, 2016 were less than $0.1 million. In addition, the Company provides certain workover rig services, fluid hauling services and plug and abandonment services to Pyote. No services were provided to Pyote during 2016. There were no amounts due to the Company from Pyote at December 31, 2016. Subsequent to the departure of the member of the Company's Board of Directors in 2016, Pyote was no longer a related party.
The Company obtains office space, equipment rentals, tool repair services and other supplies from vendors affiliated with several employees. For the years ended December 31, 2018, 2017 and 2016, purchases totaled $0.1 million, $0.5 million and $0.5 million, respectively. Amounts payable to these vendors at December 31, 2018, 2017 and 2016 were less than $0.1 million.
The Company has an unconsolidated equity method investment with a vendor that provided the Company with raw material for its discontinued specialty chemical business. For the years ended December 31, 2016, purchases from this vendor were $1.7 million. There were no purchases from this vendor for the year ended December 31, 2018 and 2017. There were no amounts payable to this vendor as of December 31, 2018 and 2017.
Note 7 - Business Concentrations
Concentration of Credit Risk
Financial instruments that potentially subject the Company to concentrations of credit risk consist primarily of cash and cash equivalents and accounts receivable. Concentrations of credit risk with respect to accounts receivable are limited because the Company performs credit evaluations, sets credit limits, and monitors the payment patterns of its customers. Cash balances on deposits with financial institutions, at times, may exceed federally insured limits. The Company regularly monitors the institutions’ financial condition.
The Company’s top ten customers accounted for approximately 44.2%, 40.7% and 46.0% of the Company’s consolidated revenue for the years ended December 31, 2018, 2017 and 2016, respectively. For the years ended December 31, 2018, 2017 and 2016, no individual customer accounted for 10.0% or more of the Company's consolidated revenue.
Note 8 - Commitments and Contingencies
Environmental Regulations & Liabilities
The Company is subject to various federal, state and local environmental laws and regulations that establish standards and requirements for the protection of the environment. These laws and regulations can change from time to time and may have retroactive effectiveness and impose new obligations on the Company. The Company continues to monitor the status of these laws and regulations. However, the Company cannot predict the future impact of such standards and requirements on its business.
Environmental risk is inherent to the Company's business and the Company maintains insurance coverage to mitigate its exposure to environmental liabilities. Currently, the Company is not aware of any environmental violations or liabilities that would have a material adverse effect upon its consolidated financial position, liquidity or capital resources. However, management does recognize that by the very nature of its business, material costs could be incurred from time to time to maintain compliance or in response to an environmental incident. The amount of such future expenditures is not determinable due to several factors, including the unknown magnitude of possible regulation or liabilities, the unknown timing and extent of the corrective actions which may be required, the determination of the Company’s liability in proportion to other responsible parties and the extent to which such expenditures are recoverable from insurance or indemnification.
Litigation
The Company is, and from time to time may be, involved in claims and litigation arising in the ordinary course of business. Because there are inherent uncertainties in the ultimate outcome of such matters, it is difficult to determine or otherwise predict with any certainty the ultimate outcome of any pending or potential claims or litigation against the Company; however, management believes that the outcome of those matters that are presently known to the Company will not have a material adverse effect on the Company’s consolidated financial position, results of operations or liquidity.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Contingent Consideration Liability
On May 18, 2015, the Company acquired all of the outstanding equity interests of ESP Completion Technologies LLC, a manufacturer of wellheads, artificial lift completion tools and electric submersible pumps for approximately $34.0 million and including a contingent consideration liability valued at approximately $14.4 million at the date of the acquisition. If the acquiree was able to achieve certain levels of EBITDA over a three-year period, the Company would be obligated to make future tiered payments of up to $29.5 million. The contingent consideration liability was remeasured on a fair value basis each quarter until it expired in 2018. As of December 31, 2017, and through its expiration in 2018, the earn-out was estimated to have zero fair value and no amounts were paid upon expiration.
Operating Leases
The Company leases certain property and equipment under non-cancelable operating leases. The remaining terms of the operating leases generally range from 1 to 6 years.
Lease expense under all operating leases totaled $12.4 million, $10.6 million and $10.0 million for the years ended December 31, 2018, 2017 and 2016, respectively. As of December 31, 2018, the future minimum lease payments under non-cancelable operating leases were as follows:
Note 9 - Employee Benefit Plans
The Company maintains a contributory profit sharing plan under a 401(k) arrangement which covers all employees meeting certain eligibility requirements. Eligible employees can make annual contributions to the plan up to the maximum amount allowed by current federal regulations, but no more than 80.0% of compensation as noted in the plan document. The Company’s 401(k) contributions for the years ended December 31, 2018 and 2017 totaled $11.7 million and $3.3 million, respectively. Due to the continued market downturn and the Company's Chapter 11 Proceeding during 2016, no 401(k) contributions were made by the Company throughout 2016.
Note 10 - Acquisitions
Acquisition of O-Tex
On November 30, 2017, the Company acquired all of the outstanding equity interest of O-Tex for approximately $271.9 million, consisting of cash of approximately $132.5 million and 4.42 million shares of the Company's common stock with a fair value of $138.2 million. The Company also acquired the remaining 49.0% non-controlling interest in an O-Tex subsidiary for $1.3 million.
During the second quarter of 2018, C&J and the seller agreed to a working capital adjustment of $1.5 million in favor of C&J, which was accounted for as a reduction to the purchase price of O-Tex.
O-Tex specializes in both primary and secondary downhole specialty cementing services in most major U.S. shale plays. This strategic transaction immediately expands C&J’s cementing business with enhanced capabilities and strengthens the Company’s position as a leading oilfield services provider with a best-in-class well construction, intervention and completions platform.
The O-Tex transaction was accounted for using the acquisition method of accounting for business combinations. In applying the acquisition method of accounting, the Company was required to determine the accounting acquirer which was
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deemed to be the party possessing the controlling financial interest. The Company determined that C&J possessed the controlling financial interest.
The purchase price was allocated to the net assets acquired based upon their estimated fair values, as shown below. The estimated fair values of certain assets and liabilities, including property plant and equipment, other intangible assets, and contingencies required significant judgments and estimates.
All of the goodwill associated with the O-Tex transaction was allocated to the WC&I reporting unit. As part of the Company's test for goodwill impairment, all of the goodwill was impaired and written down to zero as of December 31, 2018. See Note 3 - Goodwill and Other Intangible Assets for further discussion.
The purchase price was initially allocated to the net assets acquired during the fourth quarter of 2017 and subsequently adjusted within the measurement period during 2018 based upon the revised estimated fair values, as follows:
The fair value and gross contractual amount of accounts receivable acquired on November 30, 2017 was $30.0 million and $30.1 million, respectively. Based on the age of certain accounts receivable, a portion of the gross contractual amount was estimated to be uncollectible.
Property, plant and equipment assets acquired consist of the following fair values and ranges of estimated useful lives. As with fair value estimates, the determination of estimated useful lives requires judgments and assumptions.
Other intangibles were assessed a fair value of $71.5 million with a weighted average amortization period of approximately 14.8 years. These intangible assets consist of customer relationships of $58.1 million, amortizable over 15 years, trade name of $11.8 million, amortizable over 15 years, and non-compete agreements of $1.6 million, amortizable over five years. The amount allocated to goodwill represents the excess of the purchase price over the fair value of the net assets acquired. Goodwill was allocated to the Company's WC&I reporting unit. The goodwill recognized as a result of the O-Tex transaction was primarily attributable to the expected increased economies of scale, enhanced capabilities and resources, and an expanded geographic footprint. The tax deductible portion of goodwill and other intangibles is $4.4 million and $10.7 million, respectively.
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The Company treated the O-Tex acquisition as a non-taxable transaction. Such treatment resulted in the acquired assets and liabilities having carryover basis for tax purposes. An estimated deferred tax liability in the amount of $31.3 million was recorded to account for the differences between the purchase price allocation and carryover tax basis.
Acquisition-related costs associated with the O-Tex transaction were expensed as incurred and totaled $4.4 million for the year ended December 31, 2017, and are included in selling, general and administrative expenses.
The results of operations for O-Tex were included in C&J's consolidated financial statements subsequent to the November 30, 2017 acquisition date through December 31, 2017 and included revenue of $16.2 million and net income of $0.4 million. The following unaudited pro forma results of operations have been prepared as though the O-Tex transaction was completed on January 1, 2016. Pro forma amounts are based on the purchase price allocation of the acquisition and are not necessarily indicative of results that may be reported in the future:
Note 11 - Segment Information
In accordance with ASC No. 280 - Segment Reporting ("ASC 280"), the Company routinely evaluates whether its separate operating and reportable segments have changed. This determination is made based on the following factors: (1) the Company’s chief operating decision maker (“CODM”) is currently managing each operating segment as a separate business and evaluating the performance of each segment and making resource allocation decisions distinctly and expects to do so for the foreseeable future, and (2) discrete financial information for each operating segment is available.
Prior to and as of the year ended December 31, 2017, the Company’s reportable segments were: (i) Completion Services and (ii) Well Support Services. Due to the significant expansion of C&J's cementing business, during the first quarter of 2018 the CODM revised the approach in which performance evaluation and resource allocation decisions are made. Discrete financial information was created to provide the segment information necessary for the CODM to manage the Company under the revised operating segment structure. As a result of this change, the Company revised its reportable segments in the first quarter of 2018 to the following: (i) Completion Services, (ii) WC&I and (iii) Well Support Services. This segment structure reflects the financial information and reports used by the Company’s management, including its CODM, to make decisions regarding the Company’s business, including performance evaluation and resource allocation decisions. As a result of the revised reportable segment structure, the Company has restated the corresponding segment information for all periods presented. In line with the discontinuance of the small, ancillary service lines and divisions in the Other Services reportable segment, subsequent to the year ended December 31, 2016, financial information for the Other Services reportable segment is only presented for the corresponding prior year period.
The following is a brief description of the Company's reportable segments:
Completion Services
The Company’s Completion Services segment consists of the following businesses and service lines: (1) fracturing services; (2) cased-hole wireline and pumping services; and (3) completion support services, which includes the Company's R&T department.
Well Construction and Intervention Services
The Company’s WC&I segment consists of the following businesses and service lines: (1) cementing services and (2) coiled tubing services. During the first quarter of 2018, the Company exited its directional drilling business.
Well Support Services
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The Company’s Well Support Services segment consists of the following businesses and service lines: (1) rig services; (2) fluids management services; and (3) other specialty well site services. During the first quarter of 2018, the Company exited its artificial lift business.
The following tables set forth certain financial information with respect to the Company’s reportable segments.
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The CODM and the rest of management evaluates reportable segment performance and allocates resources based on total earnings (loss) before net interest expense, income taxes, depreciation and amortization, other income (expense), net gain or (loss) on disposal of assets, acquisition-related costs, and non-routine items (“Adjusted EBITDA”), because Adjusted EBITDA is considered an important measure of each reportable segment’s performance. Adjusted EBITDA at the segment level is not considered to be a non-GAAP financial measure as it is the Company's segment measure of profit or loss and is required to be disclosed under GAAP pursuant to ASC 280.
Management believes that the disclosure of Adjusted EBITDA on a consolidated basis allows investors to make a direct comparison to competitors, without regard to differences in capital and financing structure. Investors should be aware, however, that there are limitations inherent in using Adjusted EBITDA as a measure of overall profitability because it excludes significant expense items. An improving trend in Adjusted EBITDA may not be indicative of an improvement in the Company’s profitability. To compensate for the limitations in utilizing Adjusted EBITDA as an operating measure, management also uses U.S. GAAP measures of performance, including operating income (loss) and net income (loss), to evaluate performance, but only with respect to the Company as a whole and not on a reportable segment basis.
As required under Item 10(e) of Regulation S-K of the Securities Exchange Act of 1934, as amended, included below is a reconciliation of consolidated Adjusted EBITDA, a non-GAAP financial measure, from net income (loss), which is the nearest comparable U.S. GAAP financial measure on a consolidated basis for the years ended December 31, 2018, 2017 and 2016.
Note 12 - Quarterly Financial Data (unaudited)
Summarized quarterly financial data for the years ended December 31, 2018 and 2017 are presented below:
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Note 13 - Supplemental Cash Flow Disclosures
Listed below are supplemental cash flow disclosures for the year ended December 31, 2018, 2017 and 2016:
Note 14 - Chapter 11 Proceeding and Emergence
Overview
On July 8, 2016, the Debtors, including C&J Corporate Services (Bermuda) Ltd. (together with the Predecessor, the “Bermudian Entities”), C&J Energy Production Services-Canada Ltd. and Mobile Data Technologies Ltd. (together, the “Canadian Entities”), entered into a Restructuring Support and Lock-Up Agreement (the “Restructuring Support Agreement”), with certain lenders (the “Supporting Lenders”) holding approximately 90.0% of the secured claims and interests arising under the Credit Agreement, dated as of March 24, 2015 (as amended and otherwise modified, the “Original Credit Agreement”). The Restructuring Support Agreement contemplated the implementation of a financial restructuring of the Company, including the elimination of all amounts owed under the Original Credit Agreement through a complete debt-to-
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equity conversion and a re-investment in the Company through an equity rights offering. This financial restructuring was effectuated through the Restructuring Plan under Chapter 11 of the Bankruptcy Code.
To implement the Restructuring Support Agreement, on July 20, 2016 (the “Petition Date”), the Debtors filed voluntary petitions for reorganization (the “Bankruptcy Petitions”) seeking relief under the provisions of Chapter 11 of the Bankruptcy Code with the United States Bankruptcy Court in the Southern District of Texas, Houston Division (the “Bankruptcy Court”), and also commenced ancillary proceedings in Canada on behalf of the Canadian Entities and a provisional liquidation proceeding in Bermuda on behalf of the Bermudian Entities. The Chapter 11 Proceeding was being administered under the caption “In re: CJ Holding Co., et al., Case No. 16-33590”. Throughout the Chapter 11 Proceeding, the Debtors continued operations and management of their assets in the ordinary course as debtors-in-possession under the jurisdiction of the Bankruptcy Court in accordance with the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court.
In accordance with the Restructuring Support Agreement, the Debtors filed the Restructuring Plan and related disclosure statement (the “Disclosure Statement”) with the Bankruptcy Court on August 19, 2016, with a first amendment to the Restructuring Plan filed on September 28, 2016 and a second amendment filed on November 3, 2016. On November 4, 2016, the Bankruptcy Court approved the Disclosure Statement, finding that the Disclosure Statement contained adequate information as required by the Bankruptcy Code. The Debtors then launched a solicitation of acceptances of the Restructuring Plan, as required by the Bankruptcy Code. On December 16, 2016, an order confirming the Restructuring Plan was entered by the Bankruptcy Court. On the Plan Effective Date, the Debtors substantially consummated the Restructuring Plan and emerged from the Chapter 11 Proceeding. As part of the transactions undertaken pursuant to the Restructuring Plan, as of the Plan Effective Date, the Successor was formed, the Predecessor's equity was canceled, the Predecessor transferred all of its assets and operations to the Successor and the Predecessor was subsequently dissolved. As a result, the Successor became the successor issuer to the Predecessor.
The key terms of the restructuring included in the Restructuring Plan were as follows:
•
Debt-to-equity Conversion: As of the Plan Effective Date, the Supporting Lenders were issued new common equity (“New Equity”) in the Successor, as the ultimate parent company of the reorganized Debtors, and all of the existing shares of the Predecessor's common equity were canceled.
•
The Rights Offering, Backstop Commitment: The Company offered its secured lenders the right to purchase New Equity in an amount of up to $200.0 million as part of the approved Restructuring Plan (the “Rights Offering”). Certain of the Supporting Lenders (the “Backstop Parties”) agreed to backstop the full amount pursuant to a Backstop Commitment Agreement, in exchange for a commitment premium of 5.0% of the $200.0 million committed amount payable in New Equity to the Backstop Parties (the “Backstop Fee”). The Rights Offering was consummated on the Plan Effective Date and the shares were issued at a price that reflects a discount of 20.0% to the Restructuring Plan value, which was $750.0 million.
•
DIP Facility: Certain of the Supporting Lenders (the “DIP Lenders”) provided a superpriority secured delayed draw term loan facility to the Predecessor in an aggregate principal amount of up to $100.0 million (the “DIP Facility”). As further discussed below, on July 25, 2016, the Bankruptcy Court entered an order approving the Debtors’ entry into the DIP Facility on an interim basis, pending a final hearing. On July 29, 2016, the Debtors entered into a superpriority secured debtor-in-possession credit agreement, among the Debtors, the DIP Lenders and Cortland Capital Market Services LLC, as Administrative Agent (the “DIP Credit Agreement”), which set forth the terms and conditions of the DIP Facility. On September 25, 2016, the Bankruptcy Court entered a final order approving entry into the DIP Facility and DIP Credit Agreement. The Company repaid all amounts outstanding under the DIP Facility on the Plan Effective Date using proceeds from the Rights Offering.
•
The New Credit Facility: The Successor and certain of its subsidiaries, as borrowers (the “Borrowers”), entered into a revolving credit and security agreement (the “New Credit Facility”) dated the Plan Effective Date with a maturity date of January 6, 2021, with PNC Bank, National Association, as administrative agent (the “Agent”). The Borrowers subsequently amended and restated the New Credit Facility in full pursuant to an amended and restated credit and security agreement (the “Amended Credit Facility”) dated May 4, 2017, with the Agent and the lenders party thereto. The Amended Credit Facility allows the Borrowers to incur revolving loans in an aggregate amount up to the lesser of $200.0 million and a borrowing base, which borrowing base is based upon the value of the Borrowers’ accounts receivable and inventory. The Amended
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Credit Facility also provides for the issuance of letters of credit, which would reduce borrowing capacity thereunder. The maturity date of the Amended Credit Facility was May 4, 2022.
•
The New Warrants: As of the Plan Effective Date, the Company agreed to issue new seven-year warrants exercisable on a net-share settled basis into up to 6.0% of the New Equity at a strike price of $27.95 per warrant (the “New Warrants”). New Warrants representing up to 2.0% of the New Equity were issued to existing holders of Predecessor common equity as a result of such holders voting as a class to accept the Restructuring Plan, and the remaining New Warrants representing up to 4.0% of the New Equity were issued to a third-party who acquired them from the representative for the Debtors' general unsecured creditors.
•
Distributions: The DIP Lenders received payment in full in cash on the Plan Effective Date from cash on hand and proceeds from the Rights Offering. The Supporting Lenders received all of the New Equity, subject to dilution on account of the Management Incentive Plan (as defined below), the Rights Offering, the Backstop Fee and the New Warrants, along with all of the subscription rights under the Rights Offering. Under the Restructuring Plan, mineral contractor claimants have or will be paid in full in the ordinary course of business. Additionally, subject to the terms of the Restructuring Plan, certain other unsecured claimants will share in a $33.0 million cash recovery pool, plus a portion of the New Warrants, as described above.
•
Management Incentive Plan: 10.0% of the New Equity was reserved for a management incentive program to be issued to management of the Company after the Plan Effective Date from time to time at the discretion of the board of the reorganized Company (the “Management Incentive Plan”). See Note 5 - Stockholders' Equity for additional information regarding the Management Incentive Plan.
•
Governance: The board of the Successor was appointed by the Supporting Lenders and includes the Successor's Chief Executive Officer.
Liabilities Subject to Compromise
As of December 31, 2016, the Company had segregated liabilities and obligations whose treatment and satisfaction were dependent on the outcome of its reorganization under the Chapter 11 Proceeding and had classified these items as liabilities subject to compromise. Generally, all actions to enforce or otherwise effect repayment of pre-petition liabilities of the Debtors, as well as all pending litigation against the Debtors, were subject to the Chapter 11 Proceeding. Liabilities subject to compromise includes only those liabilities that are obligations of the Debtors and excludes the obligations of the Predecessor's non-debtor subsidiaries.
Principal and accrued interest owed to the Supporting Lenders as of the Petition Date were settled via the issuance of New Equity under the Restructuring Plan. Interest expense incurred subsequent to the Petition Date was not accrued since it was not treated as an allowed claim under the Restructuring Plan. For the year ended December 31, 2016, the Company did not accrue interest totaling $60.5 million under the Original Credit Agreement subsequent to the Petition Date.
As of December 31, 2016, the Company classified the entire principal balance of the Revolving Credit Facility, the Five-Year Term Loans and the Seven-Year Term Loans (see Note 2 - Debt for defined terms), as well as interest that was accrued but unpaid as of the Petition Date, as liabilities subject to compromise in accordance with ASC 852 - Reorganizations. The components of liabilities subject to compromise were as follows:
C&J ENERGY SERVICES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Reorganization Items
The Company classifies all income, expenses, gains or losses that were incurred or realized as a result of the Chapter 11 Proceeding as reorganization items in its consolidated statements of operations. In addition, the Company reports professional fees and related costs associated with and incurred during the Chapter 11 Proceeding as reorganization items. The components of reorganization items are as follows:
While the Company's emergence from bankruptcy is complete, certain administrative activities will continue under the authority of the Bankruptcy Court until all disputed claims or other matters have been concluded.
Note 15 - Fresh Start Accounting
The Company adopted fresh start accounting under the provisions of ASC 852 on the Plan Effective Date in connection with the Company's emergence from bankruptcy. Although the effective date of the Restructuring Plan was January 6, 2017, the Company accounted for the consummation of the Restructuring Plan as if it had occurred on the Fresh Start Reporting Date, January 1, 2017 and implemented Fresh Start reporting as of that date. The adoption of Fresh Start accounting resulted in a new reporting entity, the Successor, for financial reporting purposes. The presentation is analogous to that of a new business entity such that on the Plan Effective Date the Successor's consolidated financial statements reflect a new capital structure with no beginning retained earnings or deficit and a new basis in the identifiable assets and liabilities assumed which includes the elimination of Predecessor accumulated depreciation and accumulated amortization. Upon the Company's emergence from the Chapter 11 Proceeding, the Company qualified for and adopted Fresh Start accounting in accordance with the provisions set forth in ASC 852 based on the following two conditions: (i) holders of existing voting shares of the Predecessor immediately before the Plan Effective Date received less than 50.0% of the voting shares of the Successor and (ii) the reorganization value of the Successor was less than its post-petition liabilities and estimated allowed claims.
As part of Fresh Start accounting, the Company was required to determine the reorganization value of the Successor upon emergence from the Chapter 11 Proceeding. Reorganization value approximates the fair value of the entity, before considering liabilities, and approximates the amount a willing buyer would pay for the assets of the entity immediately after the restructuring. The fair value of the Successor's assets was determined with the assistance of a third-party valuation expert who used available comparable market data and quotations, discounted cash flow analysis, and other methods in determining the appropriate asset fair values. The reorganization value was allocated to the Company's individual assets based on their estimated fair values.
Enterprise value, which was used to derive reorganization value, represents the estimated fair value of an entity’s capital structure which generally consists of long term debt and stockholders’ equity. The Successor’s enterprise value was approved by the Bankruptcy Court in support of the Restructuring Plan and was not to exceed $750.0 million, which represented the mid-point of a determined range of $600.0 million to $900.0 million. The Successor's enterprise value of $750.0 million was based upon $725.9 million of New Equity and New Warrants as approved by the Bankruptcy Court and $24.1 million of other liabilities that were not eliminated or discharged under the Restructuring Plan. The Successor's enterprise value was determined with the assistance of a separate third-party valuation expert who used available comparable market data and quotations, discounted cash flow analysis and other internal financial information and projections. This enterprise value combined with the Company’s Rights Offering was the basis for deriving equity value. The Company’s estimates of fair value are inherently subject to significant uncertainties and contingencies beyond its control. Accordingly,
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
there can be no assurance that the estimates, assumptions, valuations, appraisals and financial projections will be realized, and actual results could vary materially. Moreover, the market value of the Company’s common stock subsequent to its emergence from bankruptcy may differ materially from the equity valuation derived for accounting purposes.
Machinery and Equipment
The fair value of machinery and equipment was estimated with the assistance of the third-party valuation expert, and the market approach, the cost approach, and the income approach were considered for each individual asset. The market approach and the cost approach were the primary approaches that were relied upon to value these assets. Although the income approach was not applied to value the machinery and equipment assets individually, the Company did consider the earnings of the reporting unit within which each of these assets reside. Because more than one approach was used to develop a valuation, the various approaches were reconciled to determine a final value conclusion.
Under the cost approach, the valuation estimate was based upon a determination of replacement cost new ("RCN"), reproduction cost new ("CRN"), or a combination of both. Once the RCN and CRN estimates were adjusted for physical and functional conditions, they were then compared to market data and other indications of value, where available, to confirm results obtained by the cost approach. Where direct RCN estimates were not available or deemed inappropriate, the CRN for machinery and equipment was estimated using the indirect, or trending, method in which percentage changes in applicable price indices were applied to historical costs to convert them into indications of current costs. To estimate the CRN amounts, inflation indices from established external sources were then applied to historical costs to estimate the CRN for each such asset.
The Company also developed a cost approach when market information was not available, or a market approach was deemed inappropriate. In doing so, an indicated value was derived by deducting physical deterioration from the RCN or CRN of each identifiable asset. Physical deterioration is the loss in value or usefulness of a property due to the using up or expiration of its useful life caused by wear and tear, deterioration, exposure to various elements, physical stresses, and similar factors.
Under the market approach, the valuation estimate was based upon an analysis of recent sales transactions for comparable assets and took into account physical, functional and economic conditions. Where comparable sales transactions could not be reasonably obtained, the Company utilized the percent of cost technique under the market approach, which takes into consideration general sales, sales listings, and auction data for each major asset category. This information was then used in conjunction with each asset’s effective age to develop ratios between the sales price and RCN or CRN of similar asset types. A market-based depreciation curve was then developed and applied to asset categories where sufficient sales and auction information existed.
Economic obsolescence related to machinery and equipment was also considered and was applied to stacked and underutilized assets based upon the status of the asset. Economic obsolescence was also considered in situations in which the earnings of the applicable business segment in which the assets are employed suggest economic obsolescence. When penalizing assets for economic obsolescence, an additional economic obsolescence penalty was levied, while considering scrap value to be the floor value for an asset.
Land, Buildings and Leasehold Improvements
The fair value estimates of the real property assets were estimated with the assistance of the third-party valuation expert, and the market approach, the cost approach, and the income approach were considered for each of the Company's significant real property assets. The Company primarily relied upon the market and cost approaches.
In valuing the fee simple interest in the land, the Company utilized the sales comparison approach under the market approach. The sales comparison approach estimates value based upon the price in which other purchasers and sellers have agreed to transact for comparable properties. This approach is based on the principle of substitution, which states that the limits of prices, rents and rates tend to be set by the prevailing prices, rents and rates of equally desirable substitutes. In conducting the sales comparison approach, data was gathered on comparable properties and adjustments were made for factors including market conditions, size, access/frontage, zoning, location, and conditions of sale. Greatest weight was typically given to the comparable sales in proximity and similar in size to each of the owned sites.
In valuing the fee simple interest in buildings and leasehold improvements, the Company utilized the direct and indirect methods of the cost approach. For the direct method cost approach analysis, the Company first had to determine the RCN. In order to estimate the RCN of the buildings and leasehold improvements, various factors were considered including building size, year built, number of stories, and the breakout of the space, property history, maintenance history, and insurable
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
value costs. For the indirect method cost approach, the Company first had to estimate a CRN for leasehold improvements being valued via the indirect, or trending, method of the cost approach. To estimate the CRN amounts, the Company applied published inflation indices obtained from third-party sources to each asset’s historical cost to convert the known cost into an indication of current cost.
Once the RCN and CRN of the buildings and leasehold improvements was computed, the Company estimated an allowance for physical depreciation for the buildings and leasehold improvements based upon their respective age.
Intangible Assets
The financial information used to estimate the fair values of intangible assets was consistent with the information used in estimating the Company’s enterprise value. Tradenames were valued primarily utilizing the relief from royalty method of the income approach. Significant inputs and assumptions included remaining useful lives, the forecasted revenue streams, applicable royalty rates, tax rates, and applicable discount rates. Customer relationships were considered in the analysis, but based on the valuation under the excess earnings methodology, no value was attributed to customer relationships.
The following table reconciles the enterprise value to the estimated fair value of the Successor common stock as of the Fresh Start Reporting Date:
The following table reconciles the enterprise value to the reorganization value of the Successor assets on the Effective Date:
The following table summarizes the impact of the reorganization and the Fresh Start accounting adjustments on the Company's consolidated balance sheet on the Fresh Start Reporting Date. The reorganization value has been allocated to the assets acquired based upon their estimated fair values, as shown below. The estimated fair values of certain assets and liabilities, including property, plant and equipment, other intangible assets, taxes (including uncertain tax positions), and contingencies required significant judgments and estimates:
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Reorganization adjustments
(a) Represents the reorganization adjustment to cash and cash equivalents:
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(b) Represents deferred loan costs associated with the closing of the New Credit Facility.
(c) Represents the reorganization adjustment to accounts payable and accrued expenses:
(d) Represents the repayment of the DIP Facility.
(e) Represents the settlement of liabilities subject to compromise in accordance with the Restructuring Plan:
(f) Represents the reorganization adjustments to common stock and additional paid in capital:
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(g) Represents the reorganization adjustments to retained deficit:
Fresh Start adjustments
(h) Represents the Fresh Start accounting adjustments based upon the individual asset fair values.
(i) Represents the accelerated recognition of deferred gain balances of the Predecessor.
(j) Represents the tax effect of the above Fresh Start accounting adjustments.
(k) Represents the adjustment to Predecessor additional paid-in capital as a result of the elimination of Predecessor retained deficit and accumulated other comprehensive loss in accordance with ASC 852.
(l) Represents the income statement impacts of the revaluation loss of $354.0 million, after tax, and the elimination of the resulting retained deficit balance in accordance with ASC 852.
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) under the Exchange Act, the Company’s management, with the participation of the Company’s principal executive officer and principal financial officer, evaluated the effectiveness of the Company’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) and internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) as of the end of the period covered by this Annual Report. The Company’s disclosure controls and procedures are designed to provide reasonable assurance that information required to be disclosed by the Company in reports that it files under the Exchange Act is accumulated and communicated to its management, including its principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon that evaluation, the Company’s principal executive officer and principal financial officer concluded that its disclosure controls and procedures were effective to accomplish their objectives as of December 31, 2018.
Management’s Report Regarding Internal Control. Management is responsible for establishing and maintaining adequate internal control over financial reporting. The Company’s internal control over financial reporting is a process designed under the supervision of its Chief Executive Officer and Chief Financial Officer to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the Company’s financial statements for external purposes in accordance with generally accepted accounting principles. As of December 31, 2018, management, including the Company’s Chief Executive Officer and Chief Financial Officer, assessed the effectiveness of its internal control over financial reporting. Based on their assessment, management determined that the Company maintained effective internal control over financial reporting as of December 31, 2018. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. Management’s report on internal control over financial reporting is included in Part II, Item 8 “Financial Statements and Supplementary Data” of this Annual Report.
Changes in Internal Controls Over Financial Reporting. There have been no changes in our system of internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the quarter ended December 31, 2018 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
Item 9B.
Item 9B. Other Information
None.
PART III
Item 10.
Item 10. Directors, Executive Officers and Corporate Governance
Information About Our Directors and Executive Officers
The information required by this item is incorporated by reference to our definitive proxy statement for our 2019 Annual Meeting of Stockholders pursuant to Regulation 14A under the Exchange Act, which we expect to file with the SEC within 120 days after the close of the year ended December 31, 2018.
Item 11.
Item 11. Executive Compensation
The information required by this item is incorporated by reference to our definitive proxy statement for our 2019 Annual Meeting of Stockholders pursuant to Regulation 14A under the Exchange Act, which we expect to file with the SEC within 120 days after the close of the year ended December 31, 2018.
Item 12.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters
The information required by this item is incorporated by reference to our definitive proxy statement for our 2019 Annual Meeting of Stockholders pursuant to Regulation 14A under the Exchange Act, which we expect to file with the SEC within 120 days after the close of the year ended December 31, 2018.
Item 13.
Item 13. Certain Relationships and Related Transactions, and Director Independence
The information required by this item is incorporated by reference to our definitive proxy statement for our 2019 Annual Meeting of Stockholders pursuant to Regulation 14A under the Exchange Act, which we expect to file with the SEC within 120 days after the close of the year ended December 31, 2018.
Item 14.
Item 14. Principal Accounting Fees and Services
The information required by this item is incorporated by reference to our definitive proxy statement for our 2019 Annual Meeting of Stockholders pursuant to Regulation 14A under the Exchange Act, which we expect to file with the SEC within 120 days after the close of the year ended December 31, 2018.
PART IV
Item 15.
Item 15. Exhibits, Financial Statement Schedules
(a)(1) Financial Statements
Our Consolidated Financial Statements and accompanying footnotes are included under Part II, Item 8 “Financial Statements and Supplementary Data” of this Annual Report.
(a)(2) Financial Statements Schedules
All other schedules have been omitted because they are either not applicable, not required or the information called for therein appears in the consolidated financial statements or notes thereto or will be filed within the required timeframe.
(a)(2) Exhibits
The following documents are included as exhibits to this Annual Report:
*
Filed herewith
**
Furnished, herewith in accordance with Item 601(b)(32) of Regulation S-K. In accordance with Rule 406T of Regulation S-T, the information in these exhibits shall not be deemed to be “filed” for purposes of Section 18 of the Exchange Act, or otherwise subject to liability under that section, and shall not be deemed to be incorporated by reference into any filing under the Securities Act or the Exchange Act, except as expressly set forth by specific reference in such filing.
+
Management contract or compensatory plan or arrangement
Item 16. Form 10-K Summary.
None.
SIGNATURES
Pursuant to the requirements 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, this 27th day of February, 2019.
C&J Energy Services, Inc.
By:
/s/ Donald J. Gawick
Donald J. Gawick
Chief Executive Officer, President and Director
(Principal Executive Officer)
By:
/s/ Jan Kees van Gaalen
Jan Kees van Gaalen
Chief Financial Officer
(Principal Financial Officer)
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.