EDGAR 10-K Filing

Company CIK: 1403853
Filing Year: 2021
Filename: 1403853_10-K_2021_0001403853-21-000014.json

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ITEM 1. BUSINESS
Item 1. Business
Nuverra Environmental Solutions, Inc. was incorporated in Delaware on May 29, 2007 as “Heckmann Corporation.” On May 16, 2013, we changed our name to Nuverra Environmental Solutions, Inc. When used in this Annual Report, the terms “Nuverra,” the “Company,” “we,” “our,” and “us” refer to Nuverra Environmental Solutions, Inc. and its consolidated subsidiaries, unless otherwise specified.
Overview and Operations
Nuverra provides water logistics and oilfield services to customers focused on the development and ongoing production of oil and natural gas from shale formations in the United States. Our business operations are organized into three geographically distinct divisions: the Rocky Mountain division, the Northeast division and the Southern division. Within each division, we provide water transport services, disposal services, rental and other services associated with the drilling, completion, and ongoing production of shale oil and natural gas.
Rocky Mountain Division
The Rocky Mountain division is our Bakken Shale area business. The Bakken and underlying Three Forks shale formations are the two primary oil producing reservoirs currently being developed in this geographic region, which covers western North Dakota, eastern Montana, northwestern South Dakota and southern Saskatchewan.
We have operations in various locations throughout North Dakota and Montana, including yards in Dickinson, Williston, Watford City, Tioga, Stanley and Beach, North Dakota, as well as Sidney, Montana. Additionally, we operate a financial support office in Minot, North Dakota. As of December 31, 2020, we had 249 employees in the Rocky Mountain division.
Water Transport Services
We manage a fleet of 176 trucks in the Rocky Mountain division that collect and transport flowback water from drilling and completion activities, and produced water from ongoing well production activities, to either our own or third-party disposal wells throughout the region. Additionally, our trucks collect and transport fresh water from water sources to operator locations for use in well completion activities.
In the Rocky Mountain division, we own an inventory of lay flat temporary hose as well as related pumps and associated equipment used to move fresh water from water sources to operator locations for use in completion activities. We employ specially trained field personnel to manage and operate this business. For customers who have secured their own source of fresh water, we provide and operate the lay flat temporary hose equipment to move the fresh water to the drilling and completion location. We may also use third-party sources of fresh water in order to provide the water to customers as a package that includes our water transport service.
Disposal Services
We manage a network of 20 owned and leased salt water disposal wells with current capacity of approximately 82 thousand barrels of water per day, and permitted capacity of 104 thousand barrels of water per day. Our salt water disposal wells in the Rocky Mountain division are operated under the Landtech brand. Additionally, we operate a landfill facility near Watford City, North Dakota that handles the disposal of drill cuttings and other oilfield waste generated from drilling and completion activities in the region. The landfill is located on a 50-acre site with current permitted capacity of more than 1.7 million cubic yards of airspace. We believe that permitted capacity at this site could be expanded up to a total of 5.8 million cubic yards in the future.
Rental and Other Services
We maintain and lease rental equipment to oil and gas operators and others within the Rocky Mountain division. These assets include tanks, loaders, manlifts, light towers, winch trucks and other miscellaneous equipment used in drilling and completion activities. In the Rocky Mountain division, we also provide oilfield labor services, also called “roustabout work,” where our employees move, set-up and maintain the rental equipment for customers, in addition to providing other oilfield labor services.
Northeast Division
The Northeast division is comprised of the Marcellus and Utica Shale areas, both of which are predominantly natural gas producing basins. The Marcellus and Utica Shale areas are located in the northeastern United States, primarily in Pennsylvania, West Virginia, New York and Ohio.
We have operations in various locations throughout Pennsylvania, West Virginia and Ohio, including yards in Masontown and Wheeling, West Virginia, Williamsport and Wellsboro, Pennsylvania, and Cambridge and Cadiz, Ohio. As of December 31, 2020, we had 186 employees in the Northeast division.
Water Transport Services
We manage a fleet of 177 trucks in the Northeast division that collect and transport flowback water from drilling and completion activities, and produced water from ongoing well production activities, to either our own or third-party disposal wells throughout the region, or to other customer locations for reuse in completing other wells. Additionally, our trucks collect and transport fresh water from water sources to operator locations for use in well completion activities.
Disposal Services
We manage a network of 13 owned and leased salt water disposal wells with current and permitted capacity of approximately 22 thousand barrels of water per day in the Northeast division. Our salt water disposal wells in the Northeast division are operated under the Nuverra, Heckmann and Clearwater brands.
Rental and Other Services
We maintain and lease rental equipment to oil and gas operators and others within the Northeast division. These assets include tanks and winch trucks used in drilling and completion activities.
Southern Division
The Southern division is comprised of the Haynesville Shale area, a predominantly natural gas producing basin, which is located across northwestern Louisiana and eastern Texas, and extends into southwestern Arkansas. The Haynesville shale area is the third largest natural gas-producing basin in North America, according to a United States Energy Information Administration report in 2020.
We have operations in various locations throughout eastern Texas and northwestern Louisiana, including a yard in Frierson, Louisiana. Additionally, we operate a corporate support office in Houston, Texas. As of December 31, 2020, we had 62 employees in the Southern division.
Water Transport Services
We manage a fleet of 35 trucks in the Southern division that collect and transport flowback water from drilling and completion activities, and produced water from ongoing well production activities, to either our own or third-party disposal wells throughout the region. Additionally, our trucks collect and transport fresh water to operator locations for use in well completion activities.
In the Southern division, we also own and operate a 60-mile underground twin pipeline network for the collection of produced water for transport to interconnected disposal wells and the delivery of fresh water from water sources to operator locations for use in well completion activities. The pipeline network can currently handle disposal volumes up to approximately 68 thousand barrels per day with 6 disposal wells attached to the pipeline and is scalable up to approximately 106 thousand barrels per day.
Disposal Services
We manage a network of 7 owned and leased salt water disposal wells that are not connected to our pipeline with current capacity of approximately 32 thousand barrels of water per day, and permitted capacity of approximately 100 thousand barrels of water per day in the Southern division.
Rental and Other Services
We maintain and lease rental equipment to oil and gas operators and others within the Southern division. These assets include tanks and winch trucks used in drilling and completion activities.
Business Strategy
Nuverra strives to be a leader in the oilfield services sector by providing value to our customers through an integrated service offering of water management solutions. Our strategy is focused on: (1) reinvesting in our core business in order to drive organic growth and provide a stable revenue stream, (2) optimizing our asset base to capitalize on favorable industry trends, (3) providing high quality, safe and reliable service to our customers, (4) hiring, training and retaining the best employees and (5) applying technology to optimize and streamline logistics and transaction processing.
We try to focus on the produced water sub-sector across our geographies as produced water is generated with or without drilling rig activity. While completion activities tend to fluctuate throughout each industry cycle, produced water volumes typically are more stable.
Through our network of assets strategically located in the Rocky Mountain, Northeast and Southern divisions, we have built a strong reputation in the industry by providing our customers with excellent service quality over many years. Nonetheless, we maintain rigorous focus on the key factors that determine whether our customer will use our services, such as: commitment to health, safety and environment (“HS&E”); service quality, reliability, and flexibility, including regulatory compliance; price; capacity and proximity; and technology. We continue to evolve our service offerings to address the critical value drivers while adapting to the changing water management industry. The ongoing trend of integrated gathering and disposal systems is driving increased use of water pipelines, although not all geographic divisions are able to utilize pipelines in a cost effective manner due to terrain and other limiting factors. Our salt water disposal wells (or “SWDs”) and pipeline are an integral part of our produced water business that provide core assets we can leverage to provide incremental offerings on existing disposal and water midstream projects. We are also evaluating additional service line growth opportunities. As we continue to refine our portfolio and footprint, we may consider opportunistic asset sales to provide additional capital to fund our growth investments.
Market Overview
Nuverra operates in the large and fragmented market for water management. The 2020 market size in the United States (or “U.S.”) for oilfield water management was estimated to be around $23 billion. The primary services in this market estimate include water disposal, water hauling, water treatment, water acquisition, water storage, water flowback and water transport services. Nuverra provides the majority of these services, but does not have a presence in all U.S. geographic markets.
From a geographic perspective, Nuverra remains focused on being the premier service provider in our core areas of the Bakken, Marcellus, Utica and Haynesville basins. We continue to evaluate growth opportunities in other areas. However, we do not plan to enter a market unless we believe we can generate attractive profitability and returns on invested capital. While some basins offer significant levels of water management activity, excess capacity and competition make it difficult to achieve minimum economic thresholds and returns.
A significant part of the Company’s service offering involves trucking operations. As of year end 2020, Nuverra had a fleet of approximately 388 trucks, a decrease from prior years due to a decline in oil and gas drilling activities. The Company is experiencing the same driver shortage challenge that most U.S. trucking companies are facing. Drivers decreased by 22% during 2020 mainly due to market conditions.
Customers
Our customers include major domestic and international oil and natural gas companies, foreign national oil and natural gas companies and independent oil and natural gas production companies. For the year ended December 31, 2020, our three largest customers represented 34% of our total consolidated revenues. The loss of any one of these three customers could have a material adverse effect on the Company.
Competition
Our competition includes small regional service providers, as well as larger companies with operations throughout the continental United States and internationally. Some of our competitors are Select Energy Services, Inc., Key Energy Services, Inc., Basic Energy Services, Inc., NexTier Oilfield Solutions, Inc., Superior Energy Services, Inc., Clean Harbors, Inc., TETRA Technologies, Inc., Stallion Oilfield Services, LLC, Tallgrass Energy, LP, Braun Trucking, Inc., OMNI Energy Services Corp., Myers Trucking Inc., and Tri-State Oil & Gas, Inc.
Health, Safety & Environment
We are committed to excellence in HS&E in our operations, which we believe is a critical characteristic of our business. Our customers in the unconventional shale basins require us to meet high standards on HS&E matters. As a result, we believe that being an environmental solutions company with a national presence and a dedicated focus on environmental solutions is a competitive advantage relative to smaller, regional companies, as well as companies that provide certain environmental services as ancillary offerings.
Seasonality
Certain of our business divisions are impacted by seasonal factors. Generally, our business is negatively impacted during the winter months due to inclement weather, fewer daylight hours and holidays. During periods of heavy snow, ice or rain, we may be unable to move our trucks and equipment between locations, thereby reducing our ability to provide services and generate revenue. In addition, these conditions may impact our customers’ operations, and, as our customers’ drilling and/or hydraulic fracturing activities are curtailed, our services may also be reduced.
Intellectual Property
We operate under numerous trade names and own several trademarks, the most important of which are “Nuverra,” “HWR,” “Power Fuels” and “Heckmann Water Resources.”
Operating Risks
Our operations are subject to hazards inherent in our industry, including accidents and fires that could cause personal injury or loss of life, damage to or destruction of property, equipment and the environment, suspension of operations and litigation, as described in Note 21 of the Notes to the Consolidated Financial Statements herein, associated with these hazards. Because our business involves the transportation of environmentally regulated materials, we may also experience traffic accidents or pipeline breaks that may result in spills, property damage and personal injury. We have implemented a comprehensive HS&E program designed to minimize accidents in the workplace, enhance our safety programs, maintain environmental compliance and improve the efficiency of our operations.
Governmental Regulation, Including Environmental Regulation and Climate Change
Our operations are subject to stringent United States federal, state and local laws and regulations concerning the discharge of materials into the environment or otherwise relating to health and safety or the protection of the environment. Additional laws and regulations, or changes in the interpretations of existing laws and regulations, that affect our business and operations may be adopted, which may in turn impact our financial condition. The following is a summary of the more significant existing HS&E laws and regulations to which our operations are subject.
Hazardous Substances and Waste
The United States Comprehensive Environmental Response, Compensation, and Liability Act, as amended (“CERCLA” or the “Superfund” law), and comparable state laws impose liability without regard to fault or the legality of the original conduct on certain defined persons, including current and prior owners or operators of a site where a release of hazardous substances occurred and entities that disposed or arranged for the disposal of the hazardous substances found at the site. Under CERCLA, these “responsible persons” may be liable for the costs of cleaning up the hazardous substances, for damages to natural resources and for the costs of certain health studies.
In the course of our operations, we occasionally generate materials that are considered “hazardous substances” and, as a result, may incur CERCLA liability for cleanup costs. Also, claims may be filed for personal injury and property damage allegedly caused by the release of hazardous substances or other pollutants. We also generate solid wastes that are subject to the requirements of the United States Resource Conservation and Recovery Act, as amended, or “RCRA,” and comparable state statutes.
Although we use operating and disposal practices that are standard in the industry, hydrocarbons or other wastes may have been released at properties owned or leased by us now or in the past, or at other locations where these hydrocarbons and wastes were taken for disposal. Under CERCLA, RCRA and analogous state laws, we could be required to clean up contaminated property (including contaminated groundwater) or to perform remedial activities to prevent future contamination.
Air Emissions
The Clean Air Act, as amended, or “CAA,” and similar state laws and regulations restrict the emission of air pollutants and also impose various monitoring and reporting requirements. These laws and regulations may require us to obtain approvals or permits for construction, modification or operation of certain projects or facilities and may require use of emission controls.
Global Warming and Climate Change
While we do not believe our operations raise climate change issues different from those generally raised by the commercial use of fossil fuels, legislation or regulatory programs that restrict greenhouse gas emissions in areas where we conduct business or that would require reducing emissions from our truck fleet could increase our costs.
Water Discharges
We operate facilities that are subject to requirements of the United States Clean Water Act, as amended, or “CWA,” and analogous state laws for regulating discharges of pollutants into the waters of the United States and regulating quality standards for surface waters. Among other things, these laws impose restrictions and controls on the discharge of pollutants, including into navigable waters as well as the protection of drinking water sources. Spill prevention, control and counter-measure requirements under the CWA require implementation of measures to help prevent the contamination of navigable waters in the event of a hydrocarbon spill. Other requirements for the prevention of spills are established under the United States Oil Pollution Act of 1990, as amended, or “OPA”, which amended the CWA and applies to owners and operators of vessels, including barges, offshore platforms and certain onshore facilities. Under OPA, regulated parties are strictly liable for oil spills and must establish and maintain evidence of financial responsibility sufficient to cover liabilities related to an oil spill for which such parties could be statutorily responsible.
State Environmental Regulations
Our operations involve the storage, handling, transport and disposal of bulk waste materials, some of which contain oil, contaminants and other regulated substances. Various environmental laws and regulations require prevention, and where necessary, cleanup of spills and leaks of such materials and some of our operations must obtain permits that limit the discharge of materials. Failure to comply with such environmental requirements or permits may result in fines and penalties, remediation orders and revocation of permits. In Texas, we are subject to rules and regulations promulgated by the Texas Railroad Commission (the “RRC”) and the Texas Commission on Environmental Quality, including those designed to protect the environment and monitor compliance with water quality. In Louisiana, we are subject to rules and regulations promulgated by the Louisiana Department of Environmental Quality and the Louisiana Department of Natural Resources as to environmental and water quality issues, and the Louisiana Public Service Commission as to allocation of intrastate routes and territories for waste water transportation. In Pennsylvania, we are subject to the rules and regulations of the Pennsylvania Department of Environmental Protection and the Pennsylvania Public Service Commission. In Ohio, we are subject to the rules and regulations of the Ohio Department of Natural Resources and the Ohio Environmental Protection Agency. In West Virginia, we are subject to the rules and regulations of the West Virginia Department of Environmental Protection and the West Virginia Public Service Commission as to waste water transportation. In North Dakota, we are subject to the rules and regulations of the North Dakota Department of Health, the North Dakota Industrial Commission, Oil and Gas Division, and the North Dakota State Water Commission. In Montana, we are subject to the rules and regulations of the Montana Department of Environmental Quality and the Montana Board of Oil and Gas.
Occupational Safety and Health Act
We are subject to the requirements of the United States Occupational Safety and Health Act, as amended, or “OSHA,” and comparable state laws that regulate the protection of employee health and safety. OSHA’s hazard communication standard requires that information about hazardous materials used or produced in our operations be maintained and provided to employees, state and local government authorities and citizens.
Salt Water Disposal Wells
We operate salt water disposal wells that are subject to the CWA, the Safe Drinking Water Act, or “SDWA,” and state and local laws and regulations, including those established by the Underground Injection Control (“UIC”) Program of the United States Environmental Protection Agency, or “EPA,” which establishes minimum requirements for permitting, testing, monitoring, record keeping and reporting of injection well activities. Our salt water disposal wells are located in Louisiana, Montana, North Dakota, Ohio and Texas. Regulations in many states require us to obtain a permit to operate each of our salt water disposal wells in those states. These regulatory agencies have the general authority to suspend or modify one or more of these permits if continued operation of one of our salt water wells is likely to result in pollution of freshwater, tremors or earthquakes, substantial violation of permit conditions or applicable rules, or leaks to the environment. Any leakage from the subsurface portions of the salt water wells could cause degradation of fresh groundwater resources, potentially resulting in cancellation of operations of a well, issuance of fines and penalties from governmental agencies, incurrence of expenditures for remediation of the affected resource and claims by third parties for property damages and personal injuries.
Transportation Regulations
We conduct interstate motor carrier (trucking) operations that are subject to federal regulation by the Federal Motor Carrier Safety Administration, or “FMCSA,” a unit within the United States Department of Transportation, or “USDOT.” The FMCSA publishes and enforces comprehensive trucking safety regulations, including rules on commercial driver licensing, controlled substance testing, medical and other qualifications for drivers, equipment maintenance, and drivers’ hours of service, referred to as “HOS.” The agency also performs certain functions relating to such matters as motor carrier registration (licensing), insurance, and extension of credit to motor carriers’ customers. Another unit within USDOT publishes and enforces regulations regarding the transportation of hazardous materials, or “hazmat.” The waste water and other water flows we transport by truck are generally not regulated as hazmat at this time.
Our intrastate trucking operations are also subject to various states environmental and waste water transportation regulations discussed under “Environmental Regulations” above. Federal law also allows states to impose insurance and safety requirements on motor carriers conducting intrastate business within their borders, and to collect a variety of taxes and fees on an apportioned basis reflecting miles actually operated within each state.
HOS regulations establish the maximum number of hours that a commercial truck driver may work and are intended to reduce the risk of fatigue and fatigue-related crashes and harm to driver health. Due to the specialized nature of our operations in the oil and gas industry, we qualify for an exception in the federal HOS rules (i.e., the “Oilfield Exemption”). Drivers of most property-carrying commercial motor vehicles have to take at least 34 hours off duty in order to reset their accumulated hours under the 60/70-hour rule, but drivers of property-carrying commercial motor vehicles that are used exclusively to support oil and gas activities can restart with just 24 hours off under the Oilfield Exemption. However, there are other HOS regulations that affect our operations, including the 11-Hour Driving Limit, 14-Hour On Duty Limit, 30-Minute Rest Break, 60/70-Hour Limit On Duty in 7/8 consecutive days. Compliance with these rules directly impacts our operating costs.
Employees
As of December 31, 2020, we had approximately 517 full time employees, of whom 100 were executive, managerial, sales, general, administrative and accounting staff, and 417 were truck drivers, service providers and field workers. We have not experienced, and do not expect, any work stoppages, and believe that we maintain a satisfactory working relationship with our employees.
Available Information
Information that we file with or furnish to the SEC, including our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and any amendments to or exhibits included in these reports, are available free of charge on our website at www.nuverra.com soon after such reports are filed with or furnished to the SEC. From time to time, we also post announcements, updates, events, investor information and presentations on our website in addition to copies of all recent press releases. Our reports, including any exhibits included in such reports, that are filed with or furnished to the SEC are also available on the SEC’s website at www.sec.gov.
Neither the contents of our website nor that maintained by the SEC are incorporated into or otherwise a part of this filing. Further, references to the URLs for these websites are intended to be inactive textual references only.

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ITEM 1A. RISK FACTORS
Item 1A. Risk Factors
This section describes material risks to our businesses that currently are known to us. You should carefully consider the risks described below. If any of the risks and uncertainties described in the cautionary factors described below actually occur, our business, financial condition and results of operations could be materially and adversely affected. The risks and factors listed below, however, are not exhaustive. Other sections of this Annual Report on Form 10-K include additional factors that could materially and adversely impact our business, financial condition and results of operations. Moreover, we operate in a rapidly changing environment. Other known risks that we currently believe to be immaterial could become material in the future. We also are subject to legal and regulatory changes. New factors emerge from time to time and it is not possible to predict the impact of all these factors on our business, financial condition or results of operations.
Risks Related to Our Company
Our business depends on spending by our customers in the oil and natural gas industry in the United States, and this spending and our business have been, and may in the future be, adversely affected by industry and financial market conditions that are beyond our control. Continued and prolonged reductions in oil and natural gas prices and in the overall level of exploration and development may adversely affect demand and pricing for our services.
We depend on our customers’ willingness to make operating and capital expenditures to explore, develop and produce oil and natural gas in the United States. These expenditures are generally dependent on current oil and natural gas prices and the industry’s view of future oil and natural gas prices, including the industry’s view of future economic growth and the resulting impact on demand for oil and natural gas. A continued and prolonged reduction in the overall level of exploration and development activities, whether resulting from changes in oil and natural gas prices or otherwise, could materially and adversely affect us by negatively impacting utilization, demand for our services and pricing.
Industry conditions are influenced by numerous factors over which we have no control. A substantial and extended decline in oil and natural gas prices could result in significant reductions in our customers’ operating and capital expenditures, which could have a material adverse effect on our financial condition, results of operations and cash flows. Any extended decline could result in diminished demand for oilfield services and downward pressure on the prices customers are willing to pay for services such as ours. There is no guarantee that oil and natural gas prices will remain stable or increase, drilling and completion activities in basins will remain stable or increase, or we will see an increase in the demand for our services.
Our business, results of operations and financial condition have been negatively impacted by the recent COVID-19 pandemic along with an international oil supply conflict, resulting in a significant decline in oil prices, and we expect this situation may continue to have a significant adverse effect on our business, liquidity, reported results and financial condition.
The COVID-19 outbreak emanating from China in December 2019 has impacted various businesses throughout the world. The outbreak was labeled as a global pandemic in March 2020 by the World Health Organization. Governments enacted significant actions to mitigate the public health crisis, including enacting travel restrictions, the extended shutdown of certain non-essential businesses and shelter in place/stay at home orders in many of the impacted geographic regions. Additionally, beginning in early March 2020, the global oil markets were negatively impacted by an oil supply conflict occurring when the Organization of the Petroleum Exporting Countries (“OPEC+”) was initially unable to reach an agreement on production levels for crude oil, at which point Saudi Arabia and Russia initiated efforts to aggressively increase production. The convergence of these events created the unprecedented dual impact of a dramatic decline in the demand for oil coupled with the risk of substantial excess supply. The resulting negative impact to oil prices was significant with the price per barrel of West Texas Intermediate (“WTI”) crude oil plummeting 56% during March 2020. The pandemic precipitated a significant slowdown in the global economy, thereby contributing to a material reduction in consumer demand for oil, dramatically lower oil prices, and as a result, drastically lower customer demand for our services. WTI crude oil prices have risen since May 2020 and ended the year at $48.52. In addition, in January 2021, Saudi Arabia agreed to cut oil production, causing WTI crude oil prices to reach levels not seen since February 2020. Despite the improvement in the crude oil markets, drilling and completion activity remains depressed relative to the levels experienced prior to the onset of the pandemic. Our operations and financial results to date have been negatively impacted by this situation, and this situation has had a significant adverse effect on our business, liquidity, reported results and financial condition for 2020, which may continue into 2021 and beyond.
The adverse impacts we have and may continue to experience include, but are not limited to, disruptions to customer demand for our services; to commodities markets generally; to the availability of fuel, equipment and other materials; to our workforce; to customers’ ability to pay outstanding invoices or to remain solvent; or to our business relationships with subcontractors and other third-parties. Other possible risks to our business include potential limitations on oil and gas production from regulations imposed by states and other jurisdictions, a change in demand for oil and natural gas resulting from fundamental changes in how people work, travel and socialize, or litigation risk and possible loss contingencies from the impact of COVID-19, including commercial contracts, employee matters and insurance arrangements. Any such disruptions could increase our costs or otherwise have a material adverse impact on our business operations, operating results and financial condition.
Additionally, our liquidity will be negatively impacted if oil and natural gas prices do not return to levels that induce our customers to increase their expenditures on activities that drive demand for our services. We may have to draw on amounts available under our operating line of credit and otherwise seek additional forms of financing to meet our financial obligations. Obtaining such financing is not guaranteed, and is largely dependent upon market conditions and other factors. The current environment may make it even more difficult to comply with our covenants and other restrictions in our credit facilities, and a lack of confidence in our industry on the part of the financial markets may result in a lack of access to capital, any of which could lead to reduced liquidity, an event of default, inability to draw on amounts available under our operating line of credit, the possible acceleration of our outstanding debt, the exercise of certain remedies by our lender, or a limited ability or inability to refinance our debt.
The COVID-19 pandemic situation is dynamic, and updates on restrictions on travel and non-essential businesses and shelter in place/stay at home orders are continually evolving. At this point, the extent to which COVID-19 may impact our liquidity, financial condition and results of operations is uncertain as the ultimate severity and duration of the outbreak is unknown. However, this situation has had a significant adverse effect on our business, liquidity, reported results and financial condition for fiscal 2020, and we expect it to continue during fiscal 2021.
We may not be able to successfully execute our growth initiatives, including through future acquisitions and divestitures, and we may not be able to effectively integrate the businesses we do acquire and identify and manage risks inherent in such acquisitions.
Our business strategy may include growth through the acquisitions of other businesses and divestitures of non-core businesses or assets. We may not be able to identify attractive acquisition opportunities or successfully acquire identified targets. In addition, we may not be successful in integrating future acquisitions into our existing operations, which may result in unforeseen operational difficulties or diminished financial performance or require a disproportionate amount of our management’s attention. Even if we are successful in integrating future acquisitions into our existing operations, we may not derive the benefits, such as operational or administrative synergies, that we expected from such acquisitions, which may result in the investment of our capital resources without realizing the expected returns on such investment. We also may not recognize the anticipated benefits of completed dispositions or other divestitures we may pursue in the future. We may evaluate potential divestiture opportunities with respect to portions of our business from time to time that support our growth initiatives, and may determine to proceed with a divestiture opportunity if and when we believe such opportunity is consistent with our business strategy and we would be able to realize value to our stockholders in so doing. If we do not realize the expected strategic, economic or other benefits of any divestiture transaction, it could adversely affect our financial condition and results of operation.
Our operating margins and profitability may be negatively impacted by changes in fuel and energy costs. In addition, due to certain fixed costs, our operating margins and earnings may be sensitive to changes in revenues.
Our business is dependent on availability of fuel for operating our fleet of trucks. Changes and volatility in the price of crude oil can adversely impact the prices for fuel and therefore affect our operating results. The price and supply of fuel is unpredictable and fluctuates based on events beyond our control, including geopolitical developments, supply and demand for oil and natural gas, actions by OPEC+ and other oil and natural gas producers, war and unrest in oil producing countries, regional production patterns, and environmental concerns. Furthermore, our facilities, fleet and personnel subject us to fixed costs, which make our margins and earnings sensitive to changes in revenues. In periods of declining demand, we may be unable to cut costs at a rate sufficient to offset revenue declines, which may put us at a competitive disadvantage to firms with lower or more flexible cost structures, and may result in reduced operating margins and/or higher operating losses. These effects could have a material adverse effect on our financial condition, results of operations and cash flows.
Future charges due to possible impairments of assets may have a material adverse effect on our results of operations and stock price.
As discussed more fully in Note 8 of the Notes to the Consolidated Financial Statements and “Management’s Discussion and Analysis of Financial Condition and Results of Operations Impairment of Long-Lived Assets and Impairment of Goodwill” included in Item 7 herein, during the year ended December 31, 2019 we recorded a goodwill impairment charge of $29.5 million leaving no remaining goodwill on the consolidated balance sheet. Additionally, we recorded total impairment charges of $15.6 million, $0.8 million and $4.8 million for long-lived assets and long-lived assets classified as held for sale during the years ended December 31, 2020, 2019, and 2018 respectively, which were included in “Impairment of long-lived assets” in the consolidated statements of operations. If there is further deterioration in our business operations or prospects, our stock price, the broader economy or our industry, including further declines in oil and natural gas prices, the value of our long-lived assets, or those we may acquire in the future, could decrease significantly and result in additional impairment and financial statement write-offs.
The testing of long-lived assets for impairment requires us to make significant estimates about our future performance and cash flows, as well as other assumptions. These estimates can be affected by numerous factors, including changes in the composition of our reporting units; changes in economic, industry or market conditions; changes in business operations; changes in competition; or potential changes in the share price of our common stock and market capitalization. Changes in these factors, or differences in our actual performance compared with estimates of our future performance, could affect the fair value of long-lived assets, which may result in further impairment charges. We perform the assessment of potential impairment at least annually, or more often if events and circumstances require. Should the value of our long-lived assets become impaired, we would incur additional charges which could have a material adverse effect on our consolidated results of operations and could result in us incurring additional net operating losses in future periods.
Significant capital expenditures are required to conduct our business, and our failure or inability to make sufficient capital investments could significantly harm our business prospects.
The development of our business and services, excluding acquisition activities, requires capital expenditures. During the year ended December 31, 2020, we made gross cash capital expenditures of approximately $3.4 million, including expenditures to extend the useful life and productivity on our fleet of trucks, tanks, equipment and disposal wells. We continue to focus on finding ways to improve the utilization of our existing assets and optimize the allocation of resources in the various shale areas in which we operate. In addition to capital expenditures required to maintain our current level of business activity, we may incur capital expenditures to support future growth of our business. Our capital expenditure program is subject to market conditions, including customer activity levels, commodity prices, industry capacity and specific customer needs. In addition, our credit facilities currently limit the amount of our capital expenditures to $7.5 million annually.
We expect our gross capital spending levels in 2021 to remain generally consistent with 2020. Prolonged reductions or delays in capital expenditures could delay or diminish future cash flows and adversely affect our business and results of operations. Our planned capital expenditures for 2021 are expected to be financed through cash flow from operations, finance leases, borrowings under our operating line of credit, or a combination of the foregoing. Future cash flows from operations are subject to a number of risks and variables, such as the level of drilling activity and oil and natural gas production of our customers, prices of natural gas and oil, and the other risk factors discussed herein. Our ability to obtain capital from other sources, such as the capital markets, is dependent upon many of those same factors as well as the orderly functioning of credit and capital markets. To the extent we fail to have adequate funds, we could be required to further reduce or defer our capital spending, or pursue other funding alternatives which may not be as economically attractive to us, which in turn could have a materially adverse effect on our financial condition, results of operations and cash flows.
The compensation we offer our drivers is subject to market conditions, and we may find it necessary to increase driver compensation and/or modify the benefits provided to our employees in future periods.
Maintaining a staff of qualified truck drivers is critical to the success of our operations. We and other companies in the oil and natural gas industry suffer from a high turnover rate of drivers. The high turnover rate requires us to continually recruit a substantial number of drivers in order to operate existing equipment. If we are unable to continue to attract and retain a sufficient number of qualified drivers, we could be forced to, among other things, increase driver compensation and/or modify our benefit packages, or operate with fewer trucks and face difficulty meeting customer demands, any of which could adversely affect our growth and profitability. Additionally, in anticipation of or in response to geographical and market-related fluctuations in the demand for our services, we strategically relocate our equipment and personnel from one area to another, which may result in operating inefficiencies, increased labor, fuel and other operating costs and could adversely affect our growth and profitability. As a result, our driver and employee training and orientation costs could be negatively impacted. We also utilize the services of independent contractor truck drivers to supplement our trucking capacity in certain shale areas on an as-needed basis. There can be no assurance that we will be able to enter into these types of arrangements on favorable terms, or that there will be sufficient qualified independent contractors available to meet our needs, which could have a material adverse effect on our financial condition, results of operations and cash flows.
We depend on certain key customers for a significant portion of our revenues. The loss of any of these key customers or the loss of any contracted volumes could result in a decline in our business.
We rely on a limited number of customers for a significant portion of our revenues. Our three largest customers represented 34% of our total consolidated revenues for the year ended December 31, 2020 and in total equaled 27% of our consolidated accounts receivable at December 31, 2020. The loss of all, or even a portion, of the revenues from these customers, as a result of competition, market conditions or otherwise, could have a material adverse effect on our business, results of operations, financial condition, and cash flows. A reduction in exploration, development and production activities by key customers due to the current declines in oil and natural gas prices, or otherwise, could have a material adverse effect on our financial condition, results of operations and cash flows.
Customer payment delays of outstanding receivables and customer bankruptcies could have a material adverse effect on our liquidity, consolidated results of operations and consolidated financial condition.
We typically provide credit to our customers for our services, and we are therefore subject to the risk of our customers delaying or failing to pay outstanding invoices. Although we monitor individual customer financial viability in granting such credit arrangements and maintain reserves we believe are adequate to cover exposure for doubtful accounts, in weak economic environments, customers’ delays and failures to pay often increase due to, among other reasons, a reduction in our customers’ cash flow from operations and their access to credit markets. If our customers delay or fail to pay a significant amount of outstanding receivables, it could reduce our availability under our operating line of credit or otherwise have a material adverse effect on our liquidity, financial condition, results of operations and cash flows.
Some of our customers have entered bankruptcy proceedings in the past or are currently under bankruptcy proceedings, and certain of our customers’ businesses face financial challenges that put them at risk of future bankruptcies. Customer bankruptcies could delay or in some cases eliminate our ability to collect accounts receivable that are outstanding at the time the customer enters bankruptcy proceedings. We are also at risk that we may be required to refund amounts collected from a customer during the period immediately prior to that customer’s bankruptcy filing, and the amount we ultimately collect from the customer’s bankruptcy estate may be significantly less. Customer bankruptcies may also reduce our availability under our operating line of credit. Although we maintain reserves for potential customer credit losses, customer bankruptcies could result in unanticipated credit losses. As a result, if one or more of our customers enter bankruptcy proceedings, particularly our larger customers or those to whom we have greater credit exposure, it could have a material adverse impact on our liquidity, operating results and financial condition.
We may be unable to achieve or maintain pricing to our customers at a level sufficient to cover our costs, which would negatively impact our profitability.
We may be unable to charge prices to our customers that are sufficient to cover our costs. Our pricing is subject to highly competitive market conditions, and we may be unable to increase or maintain pricing as market conditions change. Likewise, customers may seek pricing declines more precipitously than our ability to reduce costs. In certain cases, we have entered into fixed price agreements with our customers, which may further limit our ability to raise the prices we charge our customers at a rate sufficient to offset any increases in our costs. Additionally, some customers’ obligations under their agreements with us may be permanently or temporarily reduced upon the occurrence of certain events, some of which are beyond our control, including force majeure events. Force majeure events may include (but are not limited to) events such as revolutions, wars, acts of enemies, embargoes, import or export restrictions, strikes, lockouts, fires, storms, floods, acts of God, explosions, mechanical or physical failures of our equipment or facilities of our customers. If the amounts we are able to charge customers are insufficient to cover our costs, or if any customer suspends, terminates or curtails its business relationship with us, the effects could have a material adverse impact on our financial condition, results of operations and cash flows.
The litigation environment in which we operate poses a significant risk to our businesses.
We are occasionally involved in the ordinary course of business in a number of lawsuits involving employment, commercial, and environmental issues, other claims for injuries and damages, and various shareholder and class action litigation, among other matters. We may experience negative outcomes in such lawsuits in the future. Any such negative outcomes could have a material adverse effect on our business, liquidity, financial condition and results of operations. We evaluate litigation claims and legal proceedings to assess the likelihood of unfavorable outcomes and to estimate, if possible, the amount of potential losses. Based on these assessments and estimates, we establish reserves and disclose the relevant litigation claims or legal proceedings, as appropriate. These assessments and estimates are based on the information available to management at the time and involve a significant amount of judgment. Actual outcomes or losses may differ materially from such assessments and estimates. The settlement or resolution of such claims or proceedings may have a material adverse effect on our results of operations. In addition, judges and juries in certain jurisdictions in which we conduct business have demonstrated a willingness to grant large verdicts, including punitive damages, to plaintiffs in personal injury, property damage and other tort cases. We use appropriate means to contest litigation threatened or filed against us, but the litigation environment in these areas poses a significant business risk to us and could cause a significant diversion of management’s time and resources, which could have a material adverse effect on our financial condition, results of operations and cash flows.
The hazards and risks associated with the transport, storage, handling and disposal of our customers’ waste (such as fires, spills, explosions and accidents) may expose us to personal injury claims, property damage claims and/or products liability claims from our employees, customers or third parties. As protection against such claims and operating hazards, we maintain insurance coverage against some, but not all, potential losses. However, we may sustain losses for uninsurable or uninsured risks, or in amounts in excess of existing insurance coverage. As more fully described in Note 21 of the Notes to Consolidated Financial Statements herein, due to the unpredictable nature of personal injury litigation, it is not possible to predict the ultimate outcome of these claims and lawsuits, and we may be held liable for significant personal injury or damage to property or third parties, or other losses, that are not fully covered by our insurance, which could have a material adverse effect on our financial condition, results of operations and cash flows.
We operate in competitive markets, and there can be no certainty that we will maintain our current customers, attract new customers or that our operating margins will not be impacted by competition.
The industries in which our business operates are highly competitive. We compete with numerous local and regional companies of varying sizes and financial resources. Competition intensified during the most recent downturn, and could further intensify in the future. Furthermore, numerous well-established companies are focusing significant resources on providing similar services to those that we provide that will compete with our services. We cannot assure you that we will be able to effectively compete with these other companies or that competitive pressures, including possible downward pressure on the prices we charge for our products and services, will not arise. In addition, any declines in oil and natural gas prices may result in competitors moving resources from higher-cost exploration and production areas to relatively lower-cost exploration and production areas where we are located thereby increasing supply and putting further downward pressure on the prices we can charge for our products and services, including our rental business. In the event that we cannot effectively compete on a continuing basis, or competitive pressures arise, such inability to compete or competitive pressures could have a material adverse effect on our financial condition, results of operations and cash flows.
Our customers’ business depends on crude oil and natural gas transportation, processing, refining, and export systems and disruptions impacting those systems could adversely impact our business.
The price our customers receive for crude oil and natural gas is significantly impacted by the cost, availability, proximity and capacity of gathering, pipeline and rail systems and centralized storage, processing, refining and export facilities. The inadequacy or unavailability of capacity in these systems and facilities could result in the deferral or cancellation of drilling and completion activities, the shut-in of producing wells, the delay or discontinuance of development plans for properties or higher operational costs for our customers. If our customers’ business operations are negatively impacted for these or other reasons, it likely would reduce customer demand for our services and negatively impact our business.
Certain shale basins, including the Bakken shale area in which our Rocky Mountain operating division is located, are particularly susceptible to increases in the cost of product transport and disruptions in transport capacity due to the long distance between the geographic area where production occurs and the locations of centralized storage, processing, refining and export facilities in other parts of the United States. Although additional pipeline infrastructure has generally increased takeaway capacity in the Bakken shale area in recent years, ongoing legal disputes regarding pipeline systems, including the current litigation regarding the Dakota Access Pipeline (“DAPL”) which became commercially operational in 2017, have resulted in periodic shutdowns of significant portions of the basin’s pipeline takeaway capacity. A temporary or permanent closure of the DAPL (which transports approximately 40% of the crude oil that is produced in the Bakken), as a result of the ongoing litigation, new regulatory provisions under the Biden administration or otherwise, would likely have an adverse effect on overall drilling and completion as well as production activity in the Bakken area. Although transport of product from the Bakken shale area historically has also occurred by rail and other means, there can be no assurance that there will be sufficient future takeaway capacity. Any temporary or permanent reduction in pipeline takeaway capacity, including the DAPL, or other constraints or disruptions impacting product transport by rail or other means, could harm our customers’ business operations and, as a result, significantly reduce the demand or pricing for our services in the impacted region. Any such reduction in demand or pricing could have a material adverse effect on our business operations, financial condition, results of operations and cash flows.
Changes to trade regulation, quotas, duties or tariffs, caused by the changing U.S. and geopolitical environments or otherwise, may increase our costs or otherwise adversely affect our business.
The implementation by governmental bodies of tariffs or trade quotas, or changes to certain inter-governmental trade agreements, could, among other things, increase the costs of fuel or equipment used in our business, or negatively impact our customers’ business in a manner that reduces demand for our services. To the extent we incur fuel price increases, we may not be able to recover such increases through pricing increases or fuel price surcharges, which could have an adverse effect on our business.
Any interruption in our services due to pipeline ruptures or spills or necessary maintenance could impair our financial performance and negatively affect our brand.
Our water transport pipelines are susceptible to ruptures and spills, particularly during start up and initial operation, and require ongoing inspection and maintenance. We may experience difficulties in maintaining the operation of our pipelines, which may cause downtime and delays. We also may be required to periodically shut down all or part of our pipelines for regulatory compliance and inspection purposes. Any interruption in our services due to pipeline breakdowns or necessary maintenance, inspection or regulatory compliance could reduce revenues and earnings and result in remediation costs. While we have business interruption insurance coverage for our pipeline which would help mitigate lost revenues and remediation costs should a rupture, spill or other shut-down occur, there can be no assurances as to how much lost revenue or remediation costs our business interruption insurance would cover, if any. Transportation interruptions at our pipelines, even if only temporary, could severely harm our business and reputation, and could have a material adverse effect on our financial condition, results of operations and cash flows.
Our operations are subject to risks inherent in the oil and natural gas industry, some of which are beyond our control. These risks may not be fully covered under our insurance policies.
Our business is subject to risks, many of which are beyond our control. We are self-insured for many of these risks, and our insurance policies may not be adequate to cover all insured losses that we might incur in our operations.
Our operations are subject to operational hazards, including accidents or equipment failures that can cause pollution and other damage to the environment, injuries to persons or property and interruptions in business operations. Pursuant to applicable law, we may be required to remediate the environmental impact of any such accidents or incidents, which may include costs related to site investigation and soil, groundwater and surface water cleanup as well as penalties, damages or other costs of remediation. In addition, hazards inherent in the oil and natural gas industry, such as, but not limited to, accidents, blowouts, fires, explosions, pollution and other damage to the environment, and hydrocarbon spills may delay or halt operations at locations we service.
The occurrence of a significant event or a series of events that together are significant, or adverse claims in excess of the insurance coverage that we maintain or that are not covered by insurance, could have a material adverse effect on our financial condition, results of operations and cash flows. Litigation arising from a catastrophic occurrence at a location where our equipment and services are being used may result in our being named as a defendant in lawsuits asserting large claims.
We self-insure against a significant portion of these liabilities. For losses in excess of our self-insurance limits, we maintain insurance from unaffiliated commercial carriers. However, our insurance may not be adequate to cover all losses or liabilities that we might incur in our operations. We maintain insurance coverage that we believe to be customary in the industry against these hazards. We may not be able to maintain adequate insurance in the future at rates we consider reasonable. In addition, insurance may not be available to cover any or all of the risks to which we are subject, or, even if available, the coverage provided by such insurance may exclude coverage for damages resulting from environmental contamination or otherwise be inadequate, or insurance premiums or other costs could make such insurance prohibitively expensive.
Improvements in or new discoveries of alternative energy technologies or our customers’ operating methodologies could have a material adverse effect on our financial condition and results of operations.
Because our business depends on the level of activity in the oil and natural gas industry, any improvement in or new discoveries of alternative energy technologies (such as wind, solar, geothermal, fuel cells and biofuels) that increase the use of alternative forms of energy and reduce the demand for oil and natural gas could have a material adverse effect on our financial condition, results of operations and cash flows. In addition, technological changes in our customers’ operating methods could decrease the need for management of water and other wellsite environmental services or otherwise affect demand for our services.
We may be adversely affected by seasonal weather conditions, natural disasters, pandemics (including the recent COVID-19 outbreak) and other catastrophic events, and by man-made problems such as terrorism, that could severely disrupt our business operations or reduce customer demand for our services.
Adverse weather conditions (including significant weather events related to climate change), natural disasters, floods, pandemics (including the recent coronavirus outbreak), acts of terrorism and other catastrophic or geopolitical events may cause damage or disruption to our operations, international commerce and the global economy, or could result in market disruption or reduced customer demand for our services, any of which could have an adverse effect on our business, operating results and financial condition.
Areas in which we operate are adversely affected by seasonal weather conditions, primarily in the winter and spring. During periods of heavy snow, ice or rain, our customers may curtail their operations or we may be unable to move our trucks between locations or provide other services, thereby reducing demand for, or our ability to provide services and generate revenues. For example, many municipalities impose weight restrictions on the roads that lead to our customers’ job sites in the spring due to the muddy conditions caused by spring thaws, limiting our access and our ability to provide service in these areas. In addition, the regions in which we operate have in the past been, and may in the future be, affected by natural disasters such as hurricanes, windstorms, floods and tornadoes. In certain areas, our business may be dependent on our customers’ ability to access sufficient water supplies to support their hydraulic fracturing operations. To the extent severe drought conditions or other factors prevent our customers from accessing adequate water supplies, our business could be negatively impacted.
Our financial and operating performance may be affected by the inability to renew landfill operating permits, obtain new landfills and expand existing ones.
We currently own one landfill and our ability to meet our financial and operating objectives may depend, in part, on our ability to acquire, lease, or renew landfill operating permits, expand existing landfills and develop new landfill sites. It has become increasingly difficult and expensive to obtain required permits and approvals to build, operate and expand solid waste management facilities, including landfills. We may not be able to obtain new landfill sites or expand the permitted capacity of our landfills when necessary. In addition, we may be unable to make the contingent consideration payment required upon the issuance of a second special waste disposal permit to expand the current landfill. Any of these circumstances could have a material adverse effect on our financial condition, results of operations and cash flows.
Our ability to use net operating loss and tax credit carryforwards and certain built-in losses to reduce future tax payments may be limited. Future changes in ownership could eliminate or limit our use of net operating loss carryforwards.
Our ability to utilize our net operating loss carryforwards to offset future taxable income and to reduce federal and state income tax liabilities is subject to certain requirements, limitations and restrictions, including Internal Revenue Code Section 382 which under certain circumstances may substantially limit our ability to offset future tax liabilities with federal net operating loss carryforwards. If we undergo an ownership change, the net operating loss carryforward limitations would impose an annual limit on the amount of the taxable income that may be offset by our net operating losses generated prior to the ownership change. We have determined that an ownership change occurred on April 15, 2016 as a result of the debt restructuring that occurred during fiscal 2016. In addition, another ownership change occurred on August 7, 2017 as a result of our chapter 11
reorganization. The limitation under Section 382 may result in federal net operating loss carryforwards expiring unused. Subject to the impact of those rules as a result of past or future restructuring transactions, we may be unable to use all or a significant portion of our net operating loss carryforwards to offset future taxable income.
We manage our insurable risks through a combination of third party purchased policies and self-insurance, and we retain a substantial portion of the risk associated with expected losses under these programs, which exposes us to volatility associated with those risks, including the possibility that changes in our assumptions and estimates could have a material adverse effect on our financial condition, results of operations and cash flows.
We maintain high deductible or self-insured retention insurance policies for certain exposures including automobile liability, workers’ compensation, general liability, property damage and certain employee group health insurance plans. We carry policies for certain types of claims to provide excess coverage beyond the underlying policies and per incident deductibles or self-insured retentions. Because many claims against us do not exceed the deductibles under our insurance policies, we are effectively self-insured for a substantial portion of our claims. Given our large deductibles, we retain a substantial portion of the risk associated with expected losses under these programs. We could suffer significant losses in any given year as a result of one or multiple claims exhausting our deductible. Our insurance accruals are based on claims filed and estimates of claims incurred but not reported. The insurance accruals are influenced by our past claims experience factors, which have a limited history, and by published industry development factors. The estimates inherent in these accruals are determined using actuarial methods that are widely used and accepted in the insurance industry. If our insurance claims increase or if costs exceed our estimates of insurance liabilities, we could experience a decline in profitability and liquidity, which would adversely affect our business, financial condition or results of operations. In addition, should there be a loss or adverse judgment or other decision in an area for which we are self-insured, then our business, financial condition, results of operations and liquidity may be adversely affected.
We evaluate our insurance accruals, and the underlying assumptions, regularly throughout the year and make adjustments as needed. While we believe that the recorded amounts are reasonable, there can be no assurance that changes to our estimates will not occur due to limitations inherent in the estimation process. Changes in our assumptions and estimates could have a material adverse effect on our financial condition, results of operations and cash flows.
Concentration of ownership among our Significant Shareholders may prevent new investors from influencing significant corporate decisions and may result in conflicts of interest.
Two shareholder groups (the “Significant Shareholders”) beneficially own approximately 87% of our issued and outstanding common stock and, therefore, have significant control on the outcome of matters submitted to a vote of shareholders, including, but not limited to, electing directors and approving corporate transactions. As a result, the Significant Shareholders are able to exercise significant influence over all matters requiring shareholder approval, including: the election of directors; approval of mergers or a sale of all or substantially all of our assets and other significant corporate transactions; and the amendment of our Certificate of Incorporation and our Bylaws. Circumstances may occur in which the interests of the Significant Shareholders could be in conflict with the interests of other shareholders, and the Significant Shareholders would have substantial influence to cause us to take actions that align with their interests. Should conflicts arise, we can provide no assurance that the Significant Shareholders would act in the best interests of other shareholders or that any conflicts of interest would be resolved in a manner favorable to our other shareholders. In addition, this significant concentration of share ownership may adversely affect the trading price of our common stock because investors often perceive disadvantages in owning common stock in companies with Significant Shareholders.
Risks Related to Our Indebtedness
The amount of our debt and the covenants in the agreements governing our debt could negatively impact our business operations, financial condition, results of operations and business prospects.
As of December 31, 2020, we had approximately $35.0 million of total debt. Our level of indebtedness and the covenants contained in the agreements governing our debt, could have important consequences for our operations, including requiring us to dedicate a substantial portion of our cash flow from operations to required payments on indebtedness, thereby reducing the availability of cash flow for working capital, capital expenditures and other general business activities. Each of our debt instruments contain certain negative covenants that impose specific restrictions on us. These restrictions include, among others, our ability to incur additional debt; operationally prepay, redeem or purchase any indebtedness; pay dividends or make other distributions; make other restricted payments and investments; create liens; transfer collateral; enter into certain merger, consolidation, reorganization, or recapitalization transactions; and merge, consolidate, or transfer or dispose of substantially all of our assets. We are also subject to a limitation on annual capital expenditures and debt service coverage ratio and must maintain a $7 million positive working capital position at all times. There are also a number of affirmative covenants with which we must comply. In addition, our $13 million equipment term loan (the “Equipment Loan”) is subject to all covenants and certifications required by the Main Street Priority Loan Facility (the “MSPLF”) as established by the Board of Governors of the Federal Reserve System under Section 13(3) of the Federal Reserve Act. A breach of any of these negative or affirmative covenants, including those under the MSPLF, could result in a default under our indebtedness. If we default, our lender will no longer be obligated to extend credit to us, and could declare all amounts of outstanding debt, together with accrued interest, to be immediately due and payable. The results of such actions would have a significant impact on our results of operations, financial position and cash flows. If new debt is added to our and our subsidiaries’ current debt levels, the related risks that we and they now face could intensify and could further exacerbate the risks associated with our indebtedness.
Our ability to meet our obligations under our indebtedness depends in part on our earnings and cash flows and those of our subsidiaries and on our ability and the ability of our subsidiaries to pay dividends or advance or repay funds to us.
We conduct all of our operations through our subsidiaries. Consequently, our ability to service our debt is dependent, in large part, upon the earnings from the businesses conducted by our subsidiaries. Our subsidiaries are separate and distinct legal entities and have no obligation to pay any amounts to us, whether by dividends, loans, advances or other payments. The ability of our subsidiaries to pay dividends and make other payments to us depends on their earnings, capital requirements and general financial conditions and is restricted by, among other things, applicable corporate and other laws and regulations as well as, in the future, agreements to which our subsidiaries may be a party.
Our borrowings under our credit facilities expose us to interest rate risk.
Our earnings are exposed to interest rate risk associated with borrowings under our credit facilities. Our credit facilities carry a floating interest rate; therefore, as interest rates increase, so will our interest costs, which may have a material adverse effect on our financial condition, results of operations and cash flows. In 2020, the Federal Reserve lowered the interest rates to 1.25% and subsequently to 0.25% in response to the escalating outbreak of the pandemic. However, there can be no assurances that interest rates will not rise in the future.
Certain covenants in our Main Street Priority Loan Facility concerning employee compensation, stock buybacks, and distributions may negatively impact our ability to attract and retain talent and may discourage an acquisition of the Company that could otherwise benefit our shareholders.
Our Equipment Loan is subject to the rules and regulations of the MSPLF. While MSPLF loans have various borrower friendly economic terms, the MSPLF also has long term restrictions on employee compensation, stock buybacks and distributions, which could negatively impact our ability to attract and retain talent and execute an acquisition, sale or other strategic transaction involving the Company. During the term of the MSPLF and for one year thereafter (the “Restricted Period”), employees or officers whose total compensation in 2019 exceeded $425,000 are restricted from receiving an increase in total annual compensation from 2019 levels and severance pay in excess of two times their 2019 compensation. These compensation restrictions may negatively impact our ability to attract, retain and integrate valuable and qualified talent as compared to competitors who are not subject to the MSPLF. In addition, we are restricted from paying dividends, making other capital distributions or repurchasing any equity securities listed on a national securities exchange during the Restricted Period. These restrictions may complicate a transaction to acquire us that would have otherwise involved stock buybacks, post-closing dividends or distributions of cash to shareholders, which may make a sale of the Company significantly more costly and less attractive to a buyer. In addition, the compensation restrictions may make it more difficult for a potential purchaser to retain, incentivize and motivate highly compensated individuals to remain with the Company following an acquisition. Further, the long term restrictions of the MSPLF may affect our ability to carry out an acquisition, sale or other strategic acquisition if the lender were to require our counterpart to contractually assume these restrictions or become a co-borrower or guarantor under the MSPLF.
Risk Factors Related To Our Common Stock
We cannot assure you that an active trading market for our common stock will develop or be maintained, and the market price of our common stock may be volatile, which could cause the value of your investment to decline.
We cannot assure you that an active public market for our common stock will develop or, if it develops, be sustained. We currently have a limited trading volume of our common stock. In the absence of an active public trading market, it may be difficult to liquidate your investment in our common stock. The trading price of our common stock on the NYSE American may fluctuate significantly. Numerous factors, including many over which we have no control, may have a significant impact on the market price of our common stock, including our operating and financial performance and prospects; our ability to repay our debt; investor perceptions of us and the industry and markets in which we operate; future sales, or the availability for sale, of equity or equity-related securities; changes in earnings estimates or buy/sell recommendations by analysts; limited trading volume of our common stock; and general financial, domestic, economic and other market conditions.
Our stock price may be volatile, which could result in substantial losses for investors in our securities, and the trading price of our common stock may not reflect accurately the value of our business.
The stock markets have experienced extreme volatility that has often been unrelated to the operating performance of particular companies. These broad market fluctuations may adversely affect the trading price of our common stock. In addition, ownership of our common stock is highly concentrated, and there are a limited number of shares available for trading on the NYSE American or any other public market. As a result, reported trading prices for our common stock at any given time may not reflect accurately the underlying economic value of our business at that time. Reported trading prices could be higher or lower than the price a shareholder would be able to receive in a sale transaction, and there can be no assurance that there will be sufficient public trading in our common stock to create a liquid trading market that accurately reflects the underlying economic value of our business.
The resale of shares of our common stock may adversely affect the market price of our common stock.
At the time of our emergence from bankruptcy in 2017, we granted registration rights to certain stockholders. The shares of our outstanding common stock held by these stockholders were registered pursuant to a registration statement filed pursuant to the Securities Act and declared effective by the SEC on May 3, 2018. In addition, on January 3, 2019, an additional 3,220,330 shares were issued to these stockholders pursuant to a rights offering. The shares held by these stockholders constitute approximately 90% of our outstanding common stock as of February 26, 2021, all of which may be sold in the public markets.
The sale of a significant number of shares of our common stock, including shares issuable upon exercise of our warrants, or substantial trading in our common stock or the perception in the market that substantial trading in our common stock will occur, may adversely affect the market price of our common stock. Further, even the perception in the public market that our existing shareholders might sell shares of common stock could depress the market price of the common stock.
If securities analysts do not publish research or reports about our business or if they downgrade our stock, the price of our stock could decline.
The trading market for our shares of common stock could rely in part on the research and reporting that industry or financial analysts publish about us or our business. We do not control these analysts. Furthermore, if one or more of the analysts who do cover us downgrades our stock, the price of our stock could decline. If one or more of these analysts ceases coverage of our company, we could lose visibility in the market, which in turn could cause our stock price to decline.
We may issue a substantial number of shares of our common stock in the future and shareholders may be adversely affected by the issuance of those shares.
We may raise additional capital by issuing shares of common stock, or other securities convertible into common stock, which will increase the number of shares of common stock outstanding and may result in substantial dilution in the equity interest of our current shareholders and may adversely affect the market price of our common stock. We had 16,002,474 shares outstanding as of February 26, 2021. The issuance, and the resale or potential resale, of shares of our common stock could adversely affect the market price of our common stock and could be dilutive to our shareholders.
Certain of our charter and bylaw provisions, Delaware law, our rights plan, and the substantial ownership of our common stock by a small number of shareholders, could subject us to anti-takeover effects or could have a material negative impact on our business.
Provisions of our certificate of incorporation and bylaws, each as amended and restated, and Delaware law, as well as our rights plan, may discourage, delay or prevent a merger or acquisition that shareholders may consider favorable, including transactions in which you might otherwise receive a premium for your shares. These provisions also could limit the price that investors might be willing to pay in the future for shares of our common stock, deter potential acquirers of our Company, and frustrate or prevent any attempts by our shareholders to replace or remove our management and board of directors “the Board”. These provisions include:
•authorizing the issuance of “blank check” preferred stock without any need for action by shareholders;
•establishing a classified Board, so that only approximately one-third of our directors are elected each year;
•providing our Board with the ability to set the number of directors and to fill vacancies on the board of directors occurring between shareholder meetings;
•providing that directors may only be removed for “cause” and only by the affirmative vote of the holders of at least a majority in voting power of our issued and outstanding capital stock; and
•limiting the ability of our shareholders to call special meetings.
In addition, on December 21, 2020, we adopted a rights agreement to implement a standard “poison pill.” In general terms, for so long as the rights issued under the rights agreement are outstanding, the rights agreement prevents any person or group from acquiring a significant percentage of our outstanding capital stock or attempting a hostile takeover of our Company by significantly diluting the ownership percentage of such person or group. The rights agreement, as amended, expires on December 21, 2021. As a result, the rights agreement has a significant anti-takeover effect.
We are also subject to provisions of the Delaware corporation law that, in general, prohibit any business combination with a beneficial owner of 15% or more of our common stock for three years following the date the beneficial owner acquired at least 15% of our stock, unless various conditions are met, such as approval of the transaction by the Board. Together, these charter and statutory provisions could make the removal of management more difficult and may discourage transactions that otherwise could involve payment of a premium over prevailing market prices for our common stock.
The existence of the foregoing provisions and anti-takeover measures, as well as the significant percentage of common stock beneficially owned by our Significant Shareholders, could limit the price that investors might be willing to pay in the future for shares of our common stock. They could also deter potential acquirers of our Company, thereby reducing the likelihood that you could receive a premium for your common stock in an acquisition.
Risks Related to Environmental and Other Governmental Regulation
We are subject to United States federal, state and local laws and regulations relating to health, safety, transportation and protection of natural resources and the environment. Under these laws and regulations, we may become liable for significant penalties, damages or costs of remediation. Any changes in laws and regulations could increase our costs of doing business.
Our operations, and those of our customers, are subject to United States federal, state and local laws and regulations relating to health, safety, transportation and protection of natural resources and the environment and worker safety, including those relating to waste management and transportation and disposal of produced water and other materials. For example, we are subject to environmental regulation relating to disposal into injection wells, which can pose some risks of environmental liability, as well as liability for property damage and personal injuries. In addition, federal, state and local laws and regulations could increase costs to our customers and possibly decrease demand for our services. For example, many of our customers have intrastate pipeline operations that are subject to regulation by various agencies of the states in which they are located. If new laws and/or regulations that further regulate intrastate pipelines are adopted in response to equipment failures, spills, negative environmental effects or public sentiment, our customers may face increased costs of compliance, and thus reduce demand for our services.
Our business involves the use, handling, storage, and contracting for recycling or disposal of environmentally sensitive materials. Accordingly, we are subject to health and environmental regulations established by federal, state and local authorities. We also are subject to laws, ordinances and regulations governing the investigation and remediation of contamination at facilities we operate or to which we send hazardous or toxic substances or wastes for recycling or disposal. In particular, CERCLA imposes strict joint and several liability on owners and operators of facilities at, from, or to which a release of hazardous substances has occurred; on parties that generated hazardous substances that were released at such facilities; and on parties that transported or arranged for the transportation of hazardous substances to such facilities. A majority of states have adopted comparable statutes. Under CERCLA or a similar state statute, we could be held liable for all investigative and remedial costs associated with addressing such contamination. Claims alleging personal injury or property damage also could be brought against us based on alleged exposure to hazardous substances resulting from our operations.
Failure to comply with these laws and regulations could result in the assessment of significant administrative, civil or criminal penalties, imposition of cleanup and site restoration costs and liens, revocation of permits and orders to limit or cease certain operations. Additionally, future events, such as the discovery of currently unknown matters, spills caused by future pipeline ruptures, changes in existing environmental laws and regulations or their interpretation, and more vigorous enforcement policies by regulatory agencies, may give rise to expenditures or liabilities, which could impair our operations and could have a material adverse effect on our financial condition, results of operations and cash flows.
Increased regulation of hydraulic fracturing, including regulation of the quantities, sources and methods of water use and disposal, could result in reduction in drilling and completing new oil and natural gas wells or minimize water use or disposal, which could adversely impact the demand for our services.
Demand for our services depends, in large part, on the level of exploration and production of oil and natural gas and the oil and natural gas industry’s willingness to purchase our services. Most of our customer base uses hydraulic fracturing to drill new oil and natural gas wells. Hydraulic fracturing is used to release hydrocarbons, particularly natural gas, from certain geological formations. The process involves the injection of water (typically mixed with significant quantities of sand and small quantities of chemical additives) under pressure into the formation to fracture the surrounding rock and stimulate movement of hydrocarbons through the formation. The process is typically regulated by state oil and natural gas commissions and since 2005 has been exempt from federal regulation under the SDWA, except when the fracturing fluids or propping agents contain diesel fuels.
The EPA has been reviewing the potential environmental impacts of hydraulic fracturing activities. On February 11, 2014, the EPA released a revised UIC program permitting guidance for wells that use diesel fuels during hydraulic fracturing activities to clarify how companies can comply with a 2005 federal law that exempts hydraulic fracturing operations from the UIC permit requirement, except where diesel fuel is used as a fracturing fluid. On July 16, 2015, the EPA’s Inspector General (IG) issued a report entitled “Enhanced EPA Oversight and Action Can Further Protect Water Resources From the Potential Impacts of Hydraulic Fracturing” stating that the EPA should enhance its oversight of permit issuance for hydraulic fracturing by state and develop a plan for responding to concerns about chemicals used in hydraulic fracturing. On May 19, 2014, the EPA issued an Advance Notice of Proposed Rulemaking announcing its intention to develop a rule under the Toxic Substances Control Act (“TSCA”) to require disclosure of chemicals used in hydraulic fracturing. While the EPA’s regulatory agenda previously estimated that the EPA would issue a proposed TSCA rule in June 2018, the agency withdrew the action in March 2018. The EPA’s regulatory agenda stated, however, that the withdrawal does not preclude the EPA from developing a similar action in the future. On October 15, 2012, new EPA regulations under the CAA went into effect that require reductions in certain criteria and hazardous air pollutant emissions from hydraulic fracturing wells. In May 2016, the EPA issued new CAA regulations to reduce methane emissions from oil and gas operations, including hydraulic fracturing. Effective September 14, 2020 the EPA rescinded certain provisions of both the 2012 and 2016 regulations. On January 20, 2021, however, the new federal Administration announced that the EPA would review the rescission pursuant to a newly issued presidential Executive Order.
In June 2016, the EPA finalized regulations under the CWA to prohibit wastewater discharges from hydraulic fracturing and other natural gas production to municipal sewage plants (called publicly owned treatment works (“POTWs”)). The regulations went into effect on August 29, 2016 for most facilities, but the EPA extended the compliance date to August 29, 2019 for facilities that had been lawfully discharging extraction wastewater to POTWs prior to June 28, 2016. In December 2016, the EPA issued a final report entitled “Hydraulic Fracturing for Oil and Gas: Impacts from the Hydraulic Fracturing Water Cycle on Drinking Water Resources in the United States” that concluded that hydraulic fracturing can impact drinking water resources under some circumstances, but stated that the national frequency of impacts on drinking water could not be estimated due to significant data gaps and uncertainties in the available data. In March 2015, the Department of the Interior (“DOI”) issued regulations imposing stringent requirements on hydraulic fracturing wells constructed on federal lands, but the DOI rescinded the regulations in December 2017. On January 20, 2021, however, the new federal Administration announced that the DOI would review the rescission pursuant to a newly issued presidential Executive Order. During the last several sessions of Congress, legislation has been introduced to provide for federal regulation of hydraulic fracturing, including, requiring disclosure of chemicals used in the fracturing process, potentially repealing the SWDA exemption and even banning hydraulic fracturing. Similar legislation may be proposed in the future. If adopted, such legislation would add another level of regulation and permitting at the federal level for wells using hydraulic fracturing and could potentially severely restrict hydraulic fracturing. Full or partial bans on hydraulic fracturing have been enacted in some states, while laws and regulations restricting hydraulic fracturing have been adopted or are being considered in several other states, including certain states in which we operate. In November 2017, the Delaware River Basin Commission issued proposed regulations that would ban “high volume hydraulic fracturing” in certain areas of Pennsylvania, New York, New Jersey and Delaware although those regulations have not yet been finalized. Some local governments have also sought to restrict drilling.
Some regulators have adopted or are considering additional requirements for hydraulic fracturing related to seismic activities. For example, in April 2014, the Ohio Department of Natural Resources issued new guidelines that require companies to install seismic monitors for any horizontal drilling within 3 miles of a known fault or area of seismic activity greater than 2.0 magnitude and allow regulators to halt drilling in the event of an earthquake greater than 1.0 magnitude. In Texas, the RRC amended its existing oil and natural gas disposal well regulations to require applicants for new disposal wells to conduct seismic activity searches utilizing the U.S. Geological Survey to assess whether the RRC should impose limits on existing wells, including a temporary injection ban. Arkansas has prohibited waste-water injection in certain areas of the state due to concerns that hydraulic fracturing may be related to increased earthquake activity. These and other such laws and regulations could delay or curtail production of oil and natural gas by our customers, and thus reduce demand for our services. Additionally, a number of states require disclosure of the fluids used in hydraulic fracturing.
Future United States federal, state or local laws or regulations could significantly restrict, or increase costs associated with hydraulic fracturing and make it more difficult or costly for producers to conduct hydraulic fracturing operations, which could result in a decline in exploration and production. New laws and regulations, new enforcement policies by regulatory agencies and even tort litigation in some states, could also expressly restrict the quantities, sources and methods of water use and disposal in hydraulic fracturing and otherwise increase our costs and our customers’ cost of compliance, which could minimize water use and disposal needs even if other limits on drilling and completing new wells were not imposed. Any decline in exploration and production or any restrictions on water use and disposal could result in a decline in demand for our services and have a material adverse effect on our business, financial condition, results of operations and cash flows.
Delays or restrictions in obtaining permits by our customers for their operations or by us for our operations could impair our business.
In most states, our customers are required to obtain permits from one or more governmental agencies in order to perform drilling and completion activities and we may be required to procure permits for construction and operation of our disposal wells and pipelines. Such permits are typically required by state agencies, but they can be required by federal and local governmental agencies as well. The requirements for such permits vary, but with all governmental permitting processes, there is a degree of uncertainty as to whether a permit will be granted, the time it will take for a permit to be issued, and the conditions that may be imposed by the permit. Delays or restrictions in obtaining salt water disposal well permits could adversely impact our growth, which is dependent in part on new disposal capacity.
Our customers have been affected by moratoriums that have been imposed on the issuance of permits for drilling and completion activities in certain jurisdictions. For example, in December 2014, the State of New York announced a ban on high volume hydraulic fracturing in the state, and the New York legislature made the ban permanent in April 2020. A moratorium has been in place within the Delaware River Basin pending finalization of regulations by the Delaware River Basin Commission that would permanently ban high volume hydraulic fracturing in the Basin. Other states, including California, Texas, Arkansas, Pennsylvania, Wyoming and Colorado, have enacted laws and regulations applicable to our business activities, including disclosure of information regarding the substances used in hydraulic fracturing. In December 2013, the EPA issued a revised National Pollutant Discharge Elimination System permit under the CWA (which became effective on March 1, 2014) that requires oil and natural gas companies using hydraulic fracturing off the coast of California to disclose the chemicals they discharge into the ocean. Although the permit technically expired on February 28, 2019, permittees have been permitted to continue their operations pending the EPA’s renewal of the permit, provided that they gave the EPA timely notice of their intent to do so. Some drilling and completion activities by our customers may take place on federal land, requiring leases from the federal government to conduct such drilling and completion activities. In some cases, federal agencies have canceled oil and natural gas leases on federal lands. Moreover, on January 27, 2021 the new federal Administration imposed a moratorium on all new oil and natural gas leases on public lands pending completion of a comprehensive review and reconsideration of federal oil and gas permitting and leasing practices and the potential climate and other impacts associated with oil and gas activities on public lands. Consequently, our operations in certain areas of the country may be interrupted or suspended for varying lengths of time, causing a loss of revenue and potentially having a materially adverse effect on our financial condition, results of operations and cash flows.
We are subject to the trucking safety regulations, which are likely to be amended, and made stricter, as part of the initiative known as Compliance, Safety, Accountability, or “CSA.” If our current USDOT safety rating of “Satisfactory” is downgraded in connection with this initiative, our business and results of our operations may be adversely affected.
As part of the CSA initiative, the FMCSA is continuously revising its safety rating methodology and implementation of the same. These revisions will likely link safety ratings more closely to roadside inspection and driver violation data gathered and analyzed from month to month under the FMCSA’s new Safety Measurement System, or “SMS” and may place increased scrutiny on carriers transporting significant quantities of hazardous material. This linkage could result in greater variability in safety ratings than the current system. Preliminary studies by transportation consulting firms indicate that “Satisfactory” ratings (or any equivalent under a new SMS-based system) may become more difficult to achieve and maintain under such a system. If our operations lose their current “Satisfactory” rating, which is the highest and best rating under this initiative, we may lose some of our customer contracts that require such a rating, adversely affecting our financial condition, results of operations and cash flows.
General Risk Factors
Security breaches and other disruptions could compromise our information and expose us to liability, which would cause our business and reputation to suffer.
In the ordinary course of business, we collect and store sensitive data, including intellectual property, our proprietary business information and that of our customers, suppliers and business partners, and personally identifiable information of our customers and employees, in our data centers and on our networks. The secure processing, storage, maintenance and transmission of this information is critical to our operations and business strategy. Despite our security measures, our information technology and infrastructure may be vulnerable to attacks by hackers or breached due to employee error, malfeasance or other disruptions. Any such breach could compromise our networks and the information stored there could be accessed, publicly disclosed, lost or stolen. Any such access, disclosure or other loss of information could result in legal claims or proceedings, liability under laws that protect the privacy of personal information, and regulatory penalties, disrupt our operations and the services we provide to customers, and damage our reputation, and cause a loss of confidence in our products and services, which could adversely affect our business, operating margins, revenues and competitive position.
A failure in our operational systems, or those of third parties, may adversely affect our business.
Our business is dependent upon our operational and technological systems to process a large amount of data. If any of our financial, operational, or other data processing systems fail or have other significant shortcomings, our financial results could be adversely affected. Our financial results could also be adversely affected if an employee causes our operational systems to fail, either as a result of inadvertent error or by deliberately tampering with or manipulating our operational systems. In addition, dependence upon automated systems may further increase the risk that operational system flaws, employee tampering or manipulation of those systems could result in losses that are difficult to detect. We are heavily reliant on technology for communications, financial reporting, treasury management and many other important aspects of our business. Any failure in our operational systems could have a material adverse impact on our business. Third-party systems on which we rely could also suffer operational failures. Any of these occurrences could disrupt our business, including the ability to close our financial ledgers and report the results of our operations publicly on a timely basis or otherwise have a material adverse effect on our financial condition, results of operations and cash flows.

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ITEM 1B. UNRESOLVED STAFF COMMENTS
Item 1B. Unresolved Staff Comments
None.

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ITEM 2. PROPERTIES
Item 2. Properties
We lease our corporate headquarters in Scottsdale, Arizona and we own or lease numerous facilities including administrative offices, sales offices, truck yards, maintenance and warehouse facilities, and a landfill facility in seven other states. We also own or lease 46 salt water disposal wells in Louisiana, Montana, North Dakota, Ohio and Texas as of December 31, 2020. We believe that we have satisfactory title to the properties owned and used in our businesses, subject to liens for taxes not yet payable, liens incident to minor encumbrances, liens for credit arrangements (including liens under our credit facilities) and easements and restrictions that do not materially detract from the value of these properties, our interests in these properties or the use of these properties in our businesses.
We believe all properties that we currently occupy are suitable for their intended uses. We believe that we have sufficient facilities 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.

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ITEM 3. LEGAL PROCEEDINGS
Item 3. Legal Proceedings
We are party to legal proceedings and potential claims arising in the ordinary course of our business, including, but not limited to, claims related to employment matters, contractual disputes, personal injuries and property damage. In addition, various legal actions, claims and governmental inquiries and proceedings are pending or may be instituted or asserted in the future against us and our subsidiaries. See “Legal Matters” section in Note 21 of the Notes to the Consolidated Financial Statements herein for a description of our legal proceedings.

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ITEM 4. MINE SAFETY DISCLOSURE
Item 4. Mine Safety Disclosures
None.
PART II

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ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Market Information
Our common stock is listed on the NYSE American under the symbol “NES” and has been trading on the NYSE American since October 12, 2017. Prior to the commencement of our voluntarily chapter 11 proceedings, before August 7, 2017, our pre-Effective Date common stock was trading on the OTCQB U.S. Market (the “OTCQB”) beginning on January 20, 2016 under the symbol “NESC.”
As an issuer may not be listed on the OTCQB if it is subject to bankruptcy or reorganization proceedings, upon filing the Plan with the Bankruptcy Court, our pre-Effective Date common stock was removed from the OTCQB and began trading on the OTC Pink Open Market (the “OTC Pink”) under the symbol “NESCQ” beginning on May 2, 2017. As a result of the cancellation of the pre-Effective Date common stock pursuant to the Plan, the Company ceased trading on the OTC Pink on August 7, 2017, the “Effective Date”. From the Effective Date until our listing on the NYSE American on October 12, 2017, there was no active public trading market for our common stock. The Plan is a prepackaged plans of reorganization that became effective on the Effective Date when the Company and certain of its material subsidiaries filed voluntary petitions under chapter 11 of the United States Bankruptcy Code.
Holders
As of February 26, 2021, there were three shareholders of record of our common stock. The majority of the shares are held by CEDE & CO., a nominee of The Depository Trust Company. This number of record holders does not include beneficial holders whose shares are held in “street name,” meaning that the shares are held for their accounts by brokers or other nominees. In these instances, the brokers or other nominees are included in the number of record holders, but the underlying beneficial holders of the common stock held in “street name” are not.
Dividends
We have not paid any dividends on our common stock to date, and we currently do not intend to pay dividends in the future. The payment of dividends in the future will be contingent upon our revenues and earnings, if any, capital requirements and general financial condition. The payment of any dividends will be within the discretion of the “Board and will be subject to other limitations as may be contained in our agreements governing our indebtedness. It is the present intention of the Board to retain all earnings, if any, for use in our business operations and, accordingly, the Board does not anticipate declaring any dividends in the foreseeable future.
Unregistered Sales of Equity Securities
There were no unregistered sales of our equity securities during the fiscal year ended December 31, 2020.
Repurchases of Equity Securities
During the year ended December 31, 2020, there were no repurchases of our common stock.

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ITEM 6. SELECTED FINANCIAL DATA
Item 6. Selected Financial Data
We have adopted the amended rules of Regulation S-K which allow the elimination of five years of Selected Financial Data.

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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
This Management’s Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with our Consolidated Financial Statements, and the Notes and Schedules related thereto, which are included in this Annual Report.
Company Overview
Nuverra provides water logistics and oilfield services to customers focused on the development and ongoing production of oil and natural gas from shale formations in the United States. Our business operations are organized into three geographically distinct divisions: the Rocky Mountain division, the Northeast division, and the Southern division. Within each division, we provide water transport services, disposal services, and rental and other services associated with the drilling, completion, and ongoing production of shale oil and natural gas.
Rocky Mountain Division
The Rocky Mountain division is our Bakken Shale area business. The Bakken and underlying Three Forks shale formations are the two primary oil producing reservoirs currently being developed in this geographic region, which covers western North Dakota, eastern Montana, northwestern South Dakota and southern Saskatchewan. We have operations in various locations throughout North Dakota and Montana, including yards in Dickinson, Williston, Watford City, Tioga, Stanley, and Beach, North Dakota, as well as Sidney, Montana. Additionally, we operate a financial support office in Minot, North Dakota. As of December 31, 2020, we had 249 employees in the Rocky Mountain division.
Water Transport Services
We manage a fleet of 176 trucks in the Rocky Mountain division that collect and transport flowback water from drilling and completion activities, and produced water from ongoing well production activities, to either our own or third-party disposal wells throughout the region. Additionally, our trucks collect and transport fresh water from water sources to operator locations for use in well completion activities.
In the Rocky Mountain division, we own an inventory of lay flat temporary hose as well as related pumps and associated equipment used to move fresh water from water sources to operator locations for use in completion activities. We employ specially trained field personnel to manage and operate this business. For customers who have secured their own source of fresh water, we provide and operate the lay flat temporary hose equipment to move the fresh water to the drilling and completion location. We may also use third-party sources of fresh water in order to provide the water to customers as a package that includes our water transport service.
Disposal Services
We manage a network of 20 owned and leased salt water disposal wells with current capacity of approximately 82 thousand barrels of water per day, and permitted capacity of 104 thousand barrels of water per day. Our salt water disposal wells in the Rocky Mountain division are operated under the Landtech brand. Additionally, we operate a landfill facility near Watford City, North Dakota that handles the disposal of drill cuttings and other oilfield waste generated from drilling and completion activities in the region.
Rental and Other Services
We maintain and lease rental equipment to oil and gas operators and others within the Rocky Mountain division. These assets include tanks, loaders, manlifts, light towers, winch trucks, and other miscellaneous equipment used in drilling and completion activities. In the Rocky Mountain division, we also provide oilfield labor services, also called “roustabout work,” where our employees move, set-up and maintain the rental equipment for customers, in addition to providing other oilfield labor services.
Northeast Division
The Northeast division is comprised of the Marcellus and Utica Shale areas, both of which are predominantly natural gas producing basins. The Marcellus and Utica Shale areas are located in the northeastern United States, primarily in Pennsylvania, West Virginia, New York and Ohio. We have operations in various locations throughout Pennsylvania, West Virginia, and Ohio, including yards in Masontown and Wheeling, West Virginia, Williamsport and Wellsboro, Pennsylvania, and Cambridge and Cadiz, Ohio. As of December 31, 2020, we had 186 employees in the Northeast division.
Water Transport Services
We manage a fleet of 177 trucks in the Northeast division that collect and transport flowback water from drilling and completion activities, and produced water from ongoing well production activities, to either our own or third-party disposal wells throughout the region, or to other customer locations for reuse in completing other wells. Additionally, our trucks collect and transport fresh water from water sources to operator locations for use in well completion activities.
Disposal Services
We manage a network of 13 owned and leased salt water disposal wells with current and permitted capacity of approximately 22 thousand barrels of water per day in the Northeast division. Our salt water disposal wells in the Northeast division are operated under the Nuverra, Heckmann, and Clearwater brands.
Rental and Other Services
We maintain and lease rental equipment to oil and gas operators and others within the Northeast division. These assets include tanks and winch trucks used in drilling and completion activities.
Southern Division
The Southern division is comprised of the Haynesville Shale area, a predominantly natural gas producing basin, which is located across northwestern Louisiana and eastern Texas, and extends into southwestern Arkansas. We have operations in various locations throughout eastern Texas and northwestern Louisiana, including a yard in Frierson, Louisiana. Additionally, we operate a corporate support office in Houston, Texas. As of December 31, 2020, we had 62 employees in the Southern division.
Water Transport Services
We manage a fleet of 35 trucks in the Southern division that collect and transport flowback water from drilling and completion activities, and produced water from ongoing well production activities, to either our own or third-party disposal wells throughout the region. Additionally, our trucks collect and transport fresh water to operator locations for use in well completion activities.
In the Southern division, we also own and operate a 60-mile underground twin pipeline network for the collection of produced water for transport to interconnected disposal wells and the delivery of fresh water from water sources to operator locations for use in well completion activities. The pipeline network can currently handle disposal volumes up to approximately 68 thousand barrels per day with 6 disposal wells attached to the pipeline and is scalable up to approximately 106 thousand barrels per day.
Disposal Services
We manage a network of 7 owned and leased salt water disposal wells that are not connected to our pipeline with current capacity of approximately 32 thousand barrels of water per day, and permitted capacity of approximately 100 thousand barrels of water per day, in the Southern division.
Rental and Other Services
We maintain and lease rental equipment to oil and gas operators and others within the Southern division. These assets include tanks and winch trucks used in drilling and completion activities.
Acquisitions
On October 5, 2018, we completed the acquisition of Clearwater Three, LLC, Clearwater Five, LLC, and Clearwater Solutions, LLC (collectively, “Clearwater”) for an initial purchase price of $42.3 million, subject to customary working capital adjustments (the “Clearwater Acquisition”). Clearwater is a supplier of waste water disposal services used by the oil and gas industry in the Marcellus and Utica shale areas. Clearwater has three salt water disposal wells in service, all of which are located in Ohio. This acquisition expanded our service offerings in the Marcellus and Utica shale areas in our Northeast division. Refer to Note 6 in the Notes to Consolidated Financial Statements for additional information.
Trends Affecting Our Operating Results
COVID-19 Pandemic and Oil Price Declines
The outbreak of COVID-19 in the first quarter of 2020 and its continued spread across the globe throughout 2020 has resulted, and is likely to continue to result, in significant economic disruption, including reduction in energy demand and commodity price volatility that adversely impacted our business. Beginning in the first quarter of 2020, federal, state and local governments implemented significant actions to mitigate the public health crisis, including shelter-in-place orders, business closures and capacity limits, quarantines, travel restrictions, executive orders and similar restrictions intended to control the spread of COVID-19. Over the remainder of 2020, many of these restrictions were adjusted based on the severity of the COVID-19 outbreak in particular communities, sometimes resulting in an easing of restrictions while other times resulting in a reinstatement or tightening of restrictions. As a result, the economy was marked by significant uncertainty, and changes in travel patterns have resulted in a generally reduced demand for refined products, such as gasoline and jet fuel, and consequently a reduction in the demand for crude oil. The uncertainty of the ongoing COVID-19 pandemic has continued to impact travel patterns and generally depress market demand for crude oil.
Additionally, beginning in early March 2020, the global oil markets were negatively impacted by an oil supply conflict occurring when the Organization of Petroleum Exporting Countries and other oil producing nations (“OPEC+”) were initially unable to reach an agreement on production levels for crude oil, at which point Saudi Arabia and Russia initiated efforts to aggressively increase crude oil production. The result was an oversupply of oil, which put downward pressure on the price of crude oil.
The convergence of the COVID-19 pandemic and oil supply conflict created a dramatic decline in the demand and price of crude oil. The resulting impact to oil prices during the first half of 2020 was significant, with the price per barrel of West Texas Intermediate (“WTI”) crude oil plummeting 56% during March 2020. WTI oil spot prices decreased from a high of $63 per barrel in early January to a low of $9 per barrel in late April, including negative pricing for one day in April. The physical markets for crude oil showed signs of distress as spot prices were negatively impacted by the lack of available storage capacity. This significantly increased the volatility in oil prices. OPEC+ agreed in April 2020 to cut production, which began in May 2020 and continued through December 2020. The effect of the production cuts began to ease storage supply issues and stabilize crude oil markets. WTI crude oil prices began to steadily rise during May 2020, and since June 2020, prices have been above $35 per barrel. Despite the improvement in the crude oil markets, there continues to be an oversupply of crude oil, and drilling and completion activity in the United States and our markets remains depressed. While commodity prices have increased, a recent trend by our customers, at the insistence of investors, has been to limit capital expenditures to cash flow and to return any excess cash to shareholders in the form of dividends or stock repurchases and or to repay debt. This trend may limit the increase in activity and pricing by our customers despite commodity price increases as our customers focus on these objectives versus increasing production volumes.
While we experienced minimal impact in the first quarter of 2020, we experienced a significant decline in activity during the remainder of 2020. We do not foresee a return to pre-COVID-19 activity and pricing during 2021 and possibly beyond. In anticipation of a meaningful and sustained decline in our revenues, during the first quarter of 2020, we implemented a number of initiatives to adjust our cost structure, including:
•Adjusted salaries for all exempt and non-exempt non-contracted employees between 10% and 20%;
•Headcount reduction of approximately 100 employees, including changes made earlier in the first quarter of 2020;
•Reduced Chief Executive Officer’s salary by 25%, Chief Operating Officer salary by 20% and two other executives’ salaries between 10% and 20%;
•Reduced the compensation program for the non-employee Board of Directors by 25%;
•Materially scaled back operations in two completions-related businesses and closed one location; and
•Reduced other non-critical operating expenses.
Additionally, we implemented a significant reduction in our capital expenditures budget. We continue to maintain most of our pay reductions and other savings initiatives, but monitor market conditions that would necessitate increasing employee wages.
Our liquidity may be negatively impacted depending on how quickly consumer demand and oil prices return to more normalized levels. A lack of confidence in our industry on the part of the financial markets may result in a lack of access to capital, which could lead to reduced liquidity, an event of default, or an inability to access amounts available under our operating line of credit of $5.0 million, and our letter of credit facility of $5.35 million. Our operating line of credit is secured by a first lien security interest in all business assets of the Company and its subsidiaries including without limitation all accounts receivable, inventory, trademarks and intellectual property licenses to which it is a party and by a reserve Account, while the letter of credit facility is secured by a first lien security interest in all business assets of the Company and its subsidiaries and by a reserve Account.
While we are not able to estimate the full impact of the COVID-19 outbreak and oil price declines on our financial condition and future results of operations, we expect that this situation will have an adverse effect on our reported results through 2021 and possibly beyond.
Other Trends Affecting Operating Results
We continue to monitor several industry trends in the shale basins in which we operate. Our results are affected by capital expenditures made by the exploration and production operators in the shale basins in which we operate. These capital expenditures determine the level of drilling and completion activity which in turn impacts the amount of produced water, water for fracking, flowback water, drill cuttings and rental equipment requirements that create demand for our services. The primary drivers of these expenditures are current or anticipated prices of crude oil and natural gas. Prices trended lower during 2019 and continued to decline considerably during 2020. The average price per barrel of WTI crude oil was $39.16 in 2020 as compared to $56.98 in 2019. The average price per million Btu of natural gas as measured by the Henry Hub Natural Gas index was $2.03 in 2020 compared to $2.56 in 2019. See “COVID-19 Pandemic and Oil Price Declines” above for further discussion.
The rapid drop in crude prices occurred primarily in March and April 2020. In May 2020, OPEC+ began cutting oil production, which began to positively impact crude prices. Between June and December 2020, crude oil prices ranged between $35 and $49 per barrel, but prices were still below levels from earlier in 2020. The drop in crude oil prices had minimal impact on the first quarter of 2020 operating results as our customers had little time to adjust activity levels. However, our customers’ drilling and completion activity fell substantially beginning in the second quarter of 2020, with many customers also shutting in or lowering production as a result of spot crude prices falling below the cash costs of production in many basins and wells. Producers have shut-in production on a scale not seen in prior downturns and have been slower to bring wells back on line than anticipated.
During June 2020, per the North Dakota Industrial Commission, approximately 28% of daily crude oil production in the Bakken shale region was estimated to have been shut-in, contributing to a reduction of approximately 405,000 barrels per day. The curtailed production dropped the volumes of produced water accordingly. This had a dramatic negative effect on our produced water business in the Rocky Mountain division that has been slow to rebound. Additionally, in early July 2020, a United States court ruling ordered the shutdown of the DAPL over concerns on the environmental impact of the pipeline. The DAPL is a major transporter of oil volumes from the Bakken shale area. Although transport of product from the Bakken shale area historically has also occurred by rail and other means, which is a higher transportation cost than the DAPL, there can be no assurance that there will be sufficient future takeaway capacity. An appeals court has allowed the DAPL to continue to operate in the near term, but courts have also vacated needed easements making DAPL vulnerable to being shut down by government action or further litigation. The potential closure of the DAPL has customers cautious about returning to more normal business volumes and/or deferring capital expenditure projects until the litigation has been adjudicated. As a result, the recovery of the Rocky Mountain division has been slower than other oil producing basins.
The reduction in customer activity related to commodity prices most directly impacts our services that cater to drilling and completion activities. This includes fresh water transportation via lay flat hose, our rental equipment business and our landfill business in the Rocky Mountain division. Additionally, a portion of our trucking and salt water disposal business comes from completion-related flowback work; however, the majority of this business is derived from produced water transportation and disposal from existing wells. As such, we anticipate meaningful reductions in revenue and profitability to continue during fiscal 2021.
An additional important trend in recent years has been the focus of Wall Street and investors in the energy sector to encourage exploration and production operators to spend as a function of the cash flow they generate. Historically, as a result of accommodating debt and equity markets, exploration and production companies were able to spend in excess of the cash flow generated by the business. This shift in investor sentiment has brought increased capital discipline to exploration and production companies who are careful to make more selective capital allocation decisions. The drop during 2020 in underlying commodity prices, net of hedging activities, will impact our customers’ underlying cash flows and therefore their drilling plans. Additionally, following the decrease in commodity prices and the impact of COVID-19, a number of our customers witnessed a material drop in their public stock prices and received debt rating downgrades. We believe this trend will make it more difficult for our customers to raise new sources of capital, which may further limit their ability to spend capital on future drilling and completion activities.
Lastly, during 2020, we have seen an increase in reuse and water sharing in the Northeast. Some of our customers are using produced and flowback water for fracking as they have determined it is more economical to transport produced water to sites than it is to dispose of the water. Operators are also sharing water with other operators to avoid disposal. Transporting shared or reused water still requires trucking services, but it is generally shorter haul work done at an hourly rate which negatively impacts our revenues.
Other Factors Affecting Our Operating Results
Our results are also driven by a number of other factors, including (i) availability of our equipment, which we have built through acquisitions and capital expenditures, (ii) transportation costs, which are affected by fuel costs, (iii) utilization rates for our equipment, which are also affected by the level of our customers’ drilling and production activities, competition, and our ability to relocate our equipment to areas in which oil and natural gas exploration and production activities are more robust on a relative basis, (iv) the availability of qualified employees (or alternatively, subcontractors) in the areas in which we operate, (v) labor costs, (vi) changes in governmental laws and regulations at the federal, state and local levels, (vii) seasonality and weather events, (viii) pricing and (ix) our health, safety and environmental performance record.
While we have agreements in place with certain of our customers to establish pricing for our services and various other terms and conditions, these agreements typically do not contain minimum volume commitments or otherwise require the customer to use us. Accordingly, our customer agreements generally provide the customer the ability to change the relationship by either in-sourcing some or all services we have historically provided or by contracting with other service providers. As a result, even with respect to customers with which we have an agreement to establish pricing, the revenue we ultimately receive from that customer, and the mix of revenue among lines of services provided, is unpredictable and subject to variation over time.
Results of Operations: Year Ended December 31, 2020 Compared to the Year Ended December 31, 2019
The following table sets forth for each of the periods indicated our statements of operations data (dollars in thousands):
Year Ended December 31, Increase (Decrease)
2020 2019 2020 vs 2019
Revenue:
Service revenue $ 102,810 $ 152,541 $ (49,731) (32.6) %
Rental revenue 7,477 15,697 (8,220) (52.4) %
Total revenue
110,287 168,238 (57,951) (34.4) %
Costs and expenses:
Direct operating expenses
87,299 131,019 (43,720) (33.4) %
General and administrative expenses
18,960 20,864 (1,904) (9.1) %
Depreciation and amortization
28,614 36,183 (7,569) (20.9) %
Impairment of long-lived assets
15,579 766 14,813 1,933.8 %
Impairment of goodwill
- 29,518 (29,518) NM
Other, net
- (10) 10 (100.0) %
Total costs and expenses
150,452 218,340 (67,888) (31.1) %
Operating loss (40,165) (50,102) 9,937 (19.8) %
Interest expense, net (4,070) (5,227) 1,157 (22.1) %
Other income, net 216 502 (286) (57.0) %
Reorganization items, net
(111) (200) 89 (44.5) %
Loss before income taxes (44,130) (55,027) 10,897 (19.8) %
Income tax benefit (expense) (13) 90 (103) (114.4) %
Net loss
$ (44,143) $ (54,937) $ 10,794 (19.6) %
NM - Percentages over 100% are not displayed.
Service Revenue
Service revenue consists of fees charged to customers for water transport services, disposal services and other service revenues associated with the drilling, completion, and ongoing production of shale oil and natural gas.
On a consolidated basis, service revenue for the year ended December 31, 2020 was $102.8 million, down $49.7 million, or 32.6%, from $152.5 million for the year ended December 31, 2019. The decline in service revenue is primarily due to decreases in water transport services and disposal services in all three divisions. As the primary causes of the decreases in water transport services and decreases in disposal services are different for all three divisions, see “Segment Operating Results” below for further discussion.
Rental Revenue
Rental revenue consists of fees charged to customers for use of equipment owned by us, as well as other fees charged to customers for items such as delivery and pickup of equipment. Our rental business is primarily located in the Rocky Mountain division, however, we do have some rental equipment available in both the Northeast and Southern divisions.
Rental revenue for the year ended December 31, 2020 was $7.5 million, down $8.2 million, or 52.4%, from the year ended December 31, 2019 due primarily to a significant decline in drilling and completion activity and lower commodity prices, which resulted in lower utilization and the return of rental equipment by our customers in the Rocky Mountain division.
Direct Operating Expenses
The primary components of direct operating expenses are compensation costs for employees performing operational activities, third-party hauling costs, fuel costs associated with transportation and logistics activities, and costs to repair and maintain transportation, rental equipment and disposal wells.
Direct operating expenses for the year ended December 31, 2020 were $87.3 million, compared to $131.0 million for the year ended December 31, 2019, a decrease of 33.4%. The decrease is primarily attributable to lower activity levels in water transport services and disposal services and company-enacted cost cutting measures resulting in a decline in third-party hauling costs, compensation costs, and fleet-related expenses, including fuel and maintenance and repair costs. See “Segment Operating Results” below for further details on each division.
General and Administrative Expenses
General and administrative expenses for the year ended December 31, 2020 were $19.0 million, down $1.9 million from $20.9 million for the year ended December 31, 2019. The decrease was primarily due to a decrease in compensation costs resulting from broad employee wage reductions and layoffs, partially offset by $1.9 million of transaction fees during 2020 associated with the credit agreements.
Depreciation and Amortization
Depreciation and amortization for the year ended December 31, 2020 was $28.6 million, down $7.6 million from $36.2 million for the year ended December 31, 2019. The decrease is primarily attributable to lower depreciable asset base due to impairment of long-lived assets during 2020, the sale of under-utilized or non-core assets and assets becoming fully depreciated partially offset by asset additions.
Impairment of Long-Lived Assets
Long-lived assets, such as property, plant and equipment and purchased intangibles subject to amortization, are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. Due to the impacts of the outbreak of COVID-19 and the oil supply conflict between two major oil producing countries, there was a significant decline in oil prices during the first quarter of 2020, which resulted in a decrease in activities by our customers. As a result of these events, during the year ended December 31, 2020, there were indicators that the carrying values of the assets associated with the landfill in the Rocky Mountain division and trucking equipment in the Southern division were not recoverable and as a result we recorded long-lived asset impairment charges of $15.0 million. We may face additional asset impairments in the future, along with other accounting charges, if demand for our services decreases.
Additionally, during 2020, certain property classified as held for sale in the Rocky Mountain division was evaluated for impairment based on an accepted offer received by the Company for the sale of the property. As a result of that offer, an impairment charge of $0.6 million was recorded during the year ended December 31, 2020 to adjust the book value to match the fair value.
During the year ended December 31, 2019, management approved plans to sell real property located in the Northeast and Rocky Mountain divisions. The real property qualified to be classified as held for sale and as a result was recorded at the lower of net book value or fair value less costs to sell, which resulted in long-lived asset impairment charges of $0.8 million, of which $0.6 million related to the Northeast division and $0.1 million related to the Rocky Mountain division.
During the year ended December 31, 2018, management approved plans to sell certain assets located in the Southern division as a result of exiting the Eagle Ford shale area. In addition, management approved the sale of certain assets, primarily frac tanks, located in the Northeast division, that were also expected to sell within one year. These assets qualified to be classified as assets held for sale and as the fair value of the assets was lower than the net book value, we recorded an impairment charge of $4.8 million, of which $4.4 million related to the Southern division for the Eagle Ford exit, $0.3 million related to the Corporate division for the sale of certain real property in Texas approved to be sold as part of the Eagle Ford exit, and $0.1 million related to the Northeast division.
See also Note 8 in the Notes to the Consolidated Financial Statements herein for further discussion.
Impairment of Goodwill
When we reviewed goodwill for impairment as of October 1, 2019, we determined that it was more likely than not that the fair value of the reporting units were less than their carrying value. As a result, we completed the goodwill impairment test and determined that the fair value of all three reporting units was less than the carrying amount, resulting in a goodwill impairment charge of $29.5 million during the year ended December 31, 2019, which is a full impairment of all existing goodwill. Of the $29.5 million recorded for goodwill impairment during 2019, $21.9 million related to the Northeast division, $4.9 million related to the Rocky Mountain division, and $2.7 million related to the Southern division. The majority of the goodwill associated with this impairment was established based on valuation work completed at the time of the Company’s emergence from bankruptcy. During 2019, enterprise valuations in the energy sector materially decreased resulting in a lower estimated valuation of the Company and the impairment charge. See Note 8 in the Notes to the Consolidated Financial Statements herein for further details on goodwill impairment during 2019.
Other, net
On March 1, 2018, the Board determined it was in the best interest of the Company to cease our operations in the Eagle Ford shale area. In making this determination, the Board considered a number of factors, including among other things, the historical and projected financial performance of our operations in the Eagle Ford shale area, pricing for our services, capital requirements and projected returns on additional capital investment, competition, scope and scale of our business operations, and recommendations from management. We substantially exited the Eagle Ford shale area as of June 30, 2018. The total costs related to the exit recorded during the year ended December 31, 2018 were $1.1 million.
During the year ended December 31, 2019, we recorded final adjustments to the accrued lease liabilities for the both the Eagle Ford exit and the Mississippian exit in 2015 as further payments were not required.
Interest Expense, net
Interest expense primarily consists of interest costs related to our outstanding debt, accretion expense related to our asset retirement obligations and amortization of debt issuance costs.
Interest expense, net during the year ended December 31, 2020 was $4.1 million compared to $5.2 million for the year ended December 31, 2019. The decrease is primarily due to the refinancing of the First and Second Lien Term Loans (as defined below) and the lower overall effective interest rates on our outstanding debt.
Other Income, net
Other income, net was $0.2 million for the year ended December 31, 2020 compared to $0.5 million for the year ended December 31, 2019. The decrease is primarily due to $0.2 million of insurance proceeds during 2019 for business interruption coverage.
Reorganization Items, net
Expenses, gains and losses directly associated with the chapter 11 proceedings are reported as “Reorganization items, net” in the consolidated statements of operations. For the year ended December 31, 2019, these fees are primarily comprised of professional and legal fees related to our 2017 chapter 11 filing. Reorganization items were $0.1 million and 0.2 million during the year ended December 31, 2020 and 2019, respectively.
Income Taxes
Income tax expense for the year ended December 31, 2020 was $13.0 thousand (a 0.0% effective rate) compared to benefit of $0.1 million (a 0.2% effective rate) in the prior year. The effective tax rate in 2019 is primarily the result of the current year state income taxes offset by the current year state income taxes offset by the change in the deferred tax liability attributable to long-lived assets. See Note 19 in the Notes to the Consolidated Financial Statements herein for additional information on income taxes.
Segment Operating Results: Years Ended December 31, 2020 and 2019
The following table shows operating results for each of our segments for the years ended December 31, 2020 and 2019 (in thousands):
Rocky Mountain Northeast Southern Corporate/Other Total
Year ended December 31, 2020
Revenue $ 59,393 $ 34,173 $ 16,721 $ - $ 110,287
Direct operating expenses 49,245 26,040 12,014 - 87,299
Impairment of long-lived assets 12,183 - 3,396 - 15,579
Impairment of goodwill - - - - -
Operating loss (18,654) (3,761) (6,146) (11,604) (40,165)
Year ended December 31, 2019
Revenue $ 103,552 $ 44,001 $ 20,685 $ - $ 168,238
Direct operating expenses 81,529 35,836 13,654 - 131,019
Impairment of long-lived assets 120 646 - - 766
Impairment of goodwill 4,922 21,861 2,735 - 29,518
Operating loss (5,022) (27,977) (5,208) (11,895) (50,102)
Change
Revenue $ (44,159) $ (9,828) $ (3,964) $ - $ (57,951)
Direct operating expenses (32,284) (9,796) (1,640) - (43,720)
Impairment of long-lived assets 12,063 (646) 3,396 - 14,813
Impairment of goodwill (4,922) (21,861) (2,735) - (29,518)
Operating loss (13,632) 24,216 (938) 291 9,937
Rocky Mountain
The Rocky Mountain division experienced a significant slowdown in 2020, with rig count declining 56% from 52 at December 31, 2019 to 23 at December 31, 2020 in addition to producers shutting in wells due to the decline in WTI crude oil price per barrel, which averaged $39.16 for the year ended December 31, 2020 versus an average of $56.98 for the same period in 2019. Revenues for the Rocky Mountain division decreased by $44.2 million, or 43%, during 2020 as compared to 2019 primarily due to a $24.3 million, or 38%, decrease in water transport revenues from lower trucking volumes. Third-party trucking revenue decreased 60%, or $12.1 million, and company-owned trucking revenue declined 25%, or $10.9 million. Average total billable hours were down 19% compared to the prior year. While company-owned trucking activity is more levered to production water volumes, third-party trucking activity is more sensitive to drilling and completion activity, which has declined to historically low levels, thereby resulting in meaningful revenue reduction. Our rental and landfill businesses are our two service lines most levered to drilling activity, and therefore have declined by the highest percentage versus the prior period. Rental revenues decreased by 52%, or $8.0 million, in the current year due to lower utilization resulting from a significant decline in drilling activity driving the return of rental equipment. Our landfill revenues decreased 62%, or $3.2 million, compared to prior year due primarily to a 61% decrease in disposal volumes at our landfill as rigs working in the vicinity declined materially. Our salt water disposal well revenue decreased $6.4 million, or 50%, compared to prior year as well shut-ins and lower completion activity led to a 37% decrease in average barrels per day disposed during the current year, with water from producing wells continuing to maintain a base level of volume activity.
For the Rocky Mountain division, direct operating costs decreased by $32.3 million during the year ended December 31, 2020 as compared to the year ended December 31, 2019 due primarily to lower activity levels for water transport services and disposal services resulting in a decline in third-party hauling costs, compensation costs that are also impacted by company cost cutting initiatives, and fleet-related expenses, including fuel and maintenance and repair costs. The average number of drivers during the year decreased 19% from the prior year. Operating loss increased $13.6 million over the prior year period primarily due to an increase in $12.1 million in long-lived asset impairment charge (as previously discussed above in the consolidated results) and lower activity levels for water transport services and disposal services.
Northeast
Revenues for the Northeast division decreased by $9.8 million, or 22%, during 2020 as compared to 2019 due to decreases in water transport services of $5.6 million, or 19%, and disposal services of $3.9 million, or 32%. Natural gas prices per million Btu, as measured by the Henry Hub Natural Gas Index, decreased 6% from an average of $2.38 for 2019 to an average of $2.52 for 2020, contributing to a 27% rig count reduction in the Northeast operating area from 52 at December 31, 2019 to 38 at December 31, 2020. Additionally, as a result of the 25% decline in WTI crude oil prices experienced during the period, many of our customers who had historically focused on production of liquids-rich wells reduced activity levels and shut-in some production in our operating area due to lower realized prices for these products. This led to lower activity levels for both water transport services and disposal services despite the relatively lower decrease in natural gas prices versus crude oil prices. In addition to reduced drilling and completion activity due to commodity prices, our customers continued the industry trend of water reuse during completion activities. Water reuse inherently reduces trucking activity due to shorter hauling distances as water is being transported between well sites rather than to disposal wells. For our trucking services, revenues per billed hour decreased by 24% which contributed to the decline, along with disposal volumes in our salt water disposal wells by a 5% decrease in average barrels per day. These were offset by total billable hours, up 8% from the prior year and a 6% improvement in driver utilization.
For the Northeast division, direct operating costs decreased by $9.8 million during the year ended December 31, 2020 as compared to the year ended December 31, 2019 due to a combination of lower activity levels for water transport services and disposal services as well as company cost cutting initiatives resulting in a decline in compensation costs and fleet-related expenses, including fuel costs. The average number of drivers during the year decreased 20% from the prior year. Operating loss improved by $24.2 million over the prior year period primarily due to $21.9 million goodwill impairment charge during 2019 (as previously discussed above in the consolidated results), $0.6 million long-lived asset impairment charge during 2019 (as previously discussed above in the consolidated results), a $1.1 million decrease in general and administrative expenses due to headcount and compensation reductions and $0.7 million in lower depreciation and amortization expense.
Southern
Revenues for the Southern division decreased by $4.0 million, or 19%, during the year ended December 31, 2020 as compared to the year ended December 31, 2019. The decrease was due primarily to lower disposal well volumes, whether connected to the pipeline or not, resulting from an activity slowdown in the region, as evidenced by fewer rigs operating in the area as well as lower revenue per barrel. Rig count declined 18% in the area, from 49 at December 31, 2019 to 40 at December 31, 2020. Volumes received in our disposal wells not connected to our pipeline decreased by an average of 8,644 barrels per day or 30% during 2020 and volumes received in the disposal wells connected to the pipeline decreased by an average of 7,557 barrels per day or 17% during 2020.
In the Southern division, direct operating costs decreased by $1.6 million during the year ended December 31, 2020 as compared to the year ended December 31, 2019 due to lower activity levels for disposal services and water transport services. Operating loss increased by $0.9 million over the prior year period due primarily to a $3.4 million long-lived asset impairment charge during 2020 (as previously discussed above in the consolidated results) partially offset by $2.7 million goodwill impairment charge during 2019.
Corporate/Other
The costs associated with the Corporate/Other division are primarily general and administrative costs. The Corporate general and administrative costs for the year ended December 31, 2020 were $0.3 million lower than the year ended December 31, 2019 due primarily to headcount and compensation reductions, partially offset by $1.9 million of transaction fees during 2020 associated with the credit agreements.
Results of Operations: Year Ended December 31, 2019 Compared to the Year Ended December 31, 2018
The following table sets forth for each of the periods indicated our statements of operations data (dollars in thousands):
Year Ended December 31, Increase (Decrease)
2019 2018 2019 vs 2018
Revenue:
Service revenue $ 152,541 $ 181,793 $ (29,252) (16.1) %
Rental revenue 15,697 15,681 16 0.1 %
Total revenue
168,238 197,474 (29,236) (14.8) %
Costs and expenses:
Direct operating expenses
131,019 158,896 (27,877) (17.5) %
General and administrative expenses
20,864 38,510 (17,646) (45.8) %
Depreciation and amortization
36,183 46,434 (10,251) (22.1) %
Impairment of long-lived assets
766 4,815 (4,049) (84.1) %
Impairment of goodwill
29,518 - 29,518 NM
Other, net
(10) 1,119 (1,129) (100.9) %
Total costs and expenses
218,340 249,774 (31,434) (12.6) %
Operating loss (50,102) (52,300) 2,198 (4.2) %
Interest expense, net (5,227) (5,973) 746 (12.5) %
Other income, net 502 896 (394) (44.0) %
Reorganization items, net
(200) (1,679) 1,479 (88.1) %
Loss before income taxes (55,027) (59,056) 4,029 (6.8) %
Income tax benefit (expense) 90 (207) 297 (143.5) %
Net loss
$ (54,937) $ (59,263) $ 4,326 (7.3) %
NM - Percentages over 100% are not displayed.
Service Revenue
On a consolidated basis, service revenue for the year ended December 31, 2019 was $152.5 million, down $29.3 million, or 16.1%, from $181.8 million for the year ended December 31, 2018. The largest contributors to the decline in service revenues were Rocky Mountain third-party trucking activity and lay flat hose projects, slower trucking activity in the Northeast due to customers moving to reuse of produced water and overall activity declines and, in the South, the loss of a large customer that historically consumed a material percentage of the capacity on our Haynesville pipeline. These declines were partially offset by an increase in disposal revenues in all three divisions. Additionally, $1.8 million in revenues associated with the Eagle Ford Shale area were included in service revenues in the prior year but did not reoccur in 2019 due to management’s decision to exit the Eagle Ford Shale area as of March 1, 2018. As the primary causes of the decreases in water transport services and increases in disposal services are different for all three divisions, see “Segment Operating Results” below for further discussion.
Rental Revenue
Rental revenue for the year ended December 31, 2019 was $15.7 million, up $16.0 thousand, or 0.1%, from the year ended December 31, 2018. The prior year period included $0.3 million of rental revenues for the Eagle Ford Shale area that did not reoccur in 2019 due to management’s decision to exit the Eagle Ford Shale area as of March 1, 2018. When removing the impact of the Eagle Ford exit, rental revenues increased by $0.3 million primarily as a result of pricing increases implemented in the Rocky Mountain division.
Direct Operating Expenses
Direct operating expenses for the year ended December 31, 2019 were $131.0 million, compared to $158.9 million for the year ended December 31, 2018, a decrease of 17.5%. While the decrease in direct operating expenses was primarily attributable to lower activity levels for water transport services during the period, direct operating expenses improved to 77.9% of revenues from 80.5% in the prior year period as a result of favorable service mix due to more higher margin work, a reduction in outsourced trucking and active cost reduction efforts during the past year. (See “Segment Operating Results” below for further details on each division.)
General and Administrative Expenses
General and administrative expenses for the year ended December 31, 2019 were $20.9 million, down $17.6 million from $38.5 million for the year ended December 31, 2018. The decrease in general and administrative expenses was primarily attributable to higher compensation costs in the prior year, including $15.3 million related to the departures of our former Chief Executive Officer and Chief Financial Officer. Additionally, general and administrative expenses in 2018 included $1.3 million in transaction fees for the acquisition of Clearwater.
Depreciation and Amortization
Depreciation and amortization for the year ended December 31, 2019 was $36.2 million, down $10.3 million from $46.4 million for the year ended December 31, 2018. The decrease was primarily attributable to a lower depreciable asset base due to the sale of under-utilized or non-core assets, assets becoming fully depreciated and assets being classified as held for sale with the resulting cessation of depreciation.
Impairment of Long-Lived Assets
During the year ended December 31, 2019, management approved plans to sell real property located in the Northeast and Rocky Mountain divisions. The real property qualified to be classified as held for sale and as a result was recorded at the lower of net book value or fair value less costs to sell, which resulted in long-lived asset impairment charges of $0.8 million, of which $0.6 million related to the Northeast division and $0.1 million related to the Rocky Mountain division.
During the year ended December 31, 2018, management approved plans to sell certain assets located in the Southern division as a result of exiting the Eagle Ford shale area. In addition, management approved the sale of certain assets, primarily frac tanks, located in the Northeast division, that were also expected to sell within one year. These assets qualified to be classified as assets held for sale and as the fair value of the assets was lower than the net book value, we recorded an impairment charge of $4.8 million, of which $4.4 million related to the Southern division for the Eagle Ford exit, $0.3 million related to the Corporate division for the sale of certain real property in Texas approved to be sold as part of the Eagle Ford exit, and $0.1 million related to the Northeast division.
See also Note 8 in the Notes to the Consolidated Financial Statements herein for further discussion.
Impairment of Goodwill
When we reviewed goodwill for impairment as of October 1, 2019, we determined that it was more likely than not that the fair value of the reporting units were less than their carrying value. As a result, we completed the goodwill impairment test and determined that the fair value of all three reporting units was less than the carrying amount, resulting in a goodwill impairment charge of $29.5 million during the year ended December 31, 2019, which is a full impairment of all existing goodwill. Of the $29.5 million recorded for goodwill impairment during 2019, $21.9 million related to the Northeast division, $4.9 million related to the Rocky Mountain division, and $2.7 million related to the Southern division. The majority of the goodwill associated with this impairment was established based on valuation work completed at the time of the Company’s emergence from bankruptcy. During 2019, enterprise valuations in the energy sector materially decreased resulting in a lower estimated valuation of the Company and the impairment charge. See Note 8 in the Notes to the Consolidated Financial Statements herein for further details on the goodwill impairment during 2019.
Other, net
On March 1, 2018, the Board determined it was in the best interest of the Company to cease our operations in the Eagle Ford shale area. In making this determination, the Board considered a number of factors, including among other things, the historical and projected financial performance of our operations in the Eagle Ford shale area, pricing for our services, capital requirements and projected returns on additional capital investment, competition, scope and scale of our business operations, and recommendations from management. We substantially exited the Eagle Ford shale area as of June 30, 2018. The total costs related to the exit recorded during the year ended December 31, 2018 were $1.1 million.
During the year ended December 31, 2019, we recorded final adjustments to the accrued lease liabilities for the both the Eagle Ford exit and the Mississippian exit in 2015 as further payments were not required.
Interest Expense, net
Interest expense, net during the year ended December 31, 2019 was $5.2 million compared to $6.0 million for the year ended December 31, 2018. The lower interest expense was primarily due to repayment of the Bridge Term Loan (as defined below) in January of 2019 and continued principal payments on the First and Second Lien Term Loans (as defined below), offset by additional finance leases recorded upon the adoption of ASU No. 2016-02, Leases (Topic 842) (“ASC 842”) as of January 1, 2019 and as a result of our heavy duty truck replacement project.
Other Income, net
Other income, net was $0.5 million for the year ended December 31, 2019 compared to $0.9 million for the year ended December 31, 2018. The decrease was primarily attributable to a $34.0 thousand gain associated with the change in the fair value of the derivative warrant liability during the year ended December 31, 2019, compared to a $0.4 million gain during the year ended December 31, 2018. We issued warrants with derivative features upon our emergence from chapter 11 during 2017. These instruments are accounted for as derivative liabilities with any decrease or increase in the estimated fair value recorded in “Other income, net.” See Note 13 and Note 14 in the Notes to the Consolidated Financial Statements for further details on the warrants.
Reorganization Items, net
Expenses, gains and losses directly associated with the chapter 11 proceedings are reported as “Reorganization items, net” in the consolidated statements of operations for the years ended December 31, 2019 and 2018. These fees are primarily comprised of professional, legal and insurance fees, and other continuing fees related to our 2017 chapter 11 filing. Included in Reorganization items, net for the year ended December 31, 2018 was $1.3 million in chapter 11 fees paid to the United States Trustee for the District of Delaware. See Note 26 in the Notes to the Consolidated Financial Statements herein for further details.
Income Taxes
The income tax benefit for the year ended December 31, 2019 was $0.1 million (a 0.2% effective rate) compared to expense of $0.2 million (a (0.4%) effective rate) in the prior year. The effective tax rate in 2019 was primarily the result of the change in the deferred tax liability attributable to long-lived assets. See Note 19 in the Notes to the Consolidated Financial Statements herein for additional information on income taxes.
Segment Operating Results: Years Ended December 31, 2019 and 2018
The following table shows operating results for each of our segments for the years ended December 31, 2019 and 2018 (in thousands):
Rocky Mountain Northeast Southern Corporate/Other Total
Year ended December 31, 2019
Revenue $ 103,552 $ 44,001 $ 20,685 $ - $ 168,238
Direct operating expenses 81,529 35,836 13,654 - 131,019
Operating loss (5,022) (27,977) (5,208) (11,895) (50,102)
Year ended December 31, 2018
Revenue $ 127,758 $ 43,564 $ 26,152 $ - $ 197,474
Direct operating expenses 101,855 37,660 19,381 - 158,896
Operating loss (2,782) (9,059) (11,396) (29,063) (52,300)
Rocky Mountain
Revenues for the Rocky Mountain division decreased during the year ended December 31, 2019 as compared to the year ended December 31, 2018 due primarily to a $14.3 million decrease in overall water transport revenues largely stemming from lower trucking volumes outsourced to third parties and an $8.0 million reduction in water transport revenues from lay flat temporary hose projects. The decrease in trucking volumes outsourced to third parties was due to less fresh water and flowback hauling from well completion projects in the geographical areas that we serve. In addition, some of this third-party work was replaced by operators using lay flat hose. The decrease in water transport service revenues from lay flat temporary hose during 2019 was due to increased overall competition for this service and more specifically from competitors that had better access to water sources. Disposal volumes in our salt water disposal wells increased by an average of 8,379 barrels per day (or 21.7%) and revenue increased proportionally. Disposal volumes at our landfill decreased by 12,260 tons (or 6.1%) due to fewer rigs operating near our landfill, coupled with pricing pressures from competing landfills rendering our facility less attractive to customers relative to the competition. Rental revenues increased by 2.1% in 2019 due to pricing increases implemented during 2019.
For the Rocky Mountain division, direct operating costs decreased during the year ended December 31, 2019 as compared to the year ended December 31, 2018 due primarily to decreased water transport activity. Direct operating costs improved as a percentage of revenue to 78.7% in 2019 as compared to 79.7% in the prior year period. The Rocky Mountain division had a $5.0 million operating loss during 2019, as opposed to a $2.8 million loss in the prior year period, due primarily to the aforementioned factors as well as a $4.9 million goodwill impairment charge.
Northeast
Revenues for the Northeast division increased slightly during the year ended December 31, 2019 as compared to the year ended December 31, 2018. During 2019, natural gas prices, as measured by the Henry Hub Natural Gas index decreased 36% from $3.25 in 2018 to $2.09 in 2019, contributing to a 30% rig count reduction as of December 2019 in the Northeast operating area from 74 in 2018 to 52 in 2019. Also, as a result of pricing declines, customers sought to reduce costs and turned to the reuse of production water in completion activities leading to a reduction in both price and activity for our water transport services. During 2019, we experienced a shift of approximately 50% of our transportation revenue from disposal wells to reuse. Water reuse inherently reduces trucking activity due to shorter hauling distances as water is being transported between well sites rather than to disposal wells and partially negates our considerable competitive advantage of having higher barrel capacity trailers hauling to better positioned disposal wells. As a result, overall billable trucking hours declined 9% and revenue decreased from $33.9 million to $29.6 million on a year-over-year basis. However, the Clearwater Acquisition presented a transportation cost savings due to its proximity to customers and generated salt water disposal revenues sufficient to offset the declines in trucking.
For the Northeast division, direct operating costs decreased during the year ended December 31, 2019 as compared to the year ended December 31, 2018 primarily due to proportionally higher disposal volumes which generate lower costs on a dollar of revenue as compared to our trucking operations. Direct operating costs improved as a percentage of revenue to 81.4% in 2019 as compared to 86.4% in the prior year period due to the increase in higher margin disposal services. Operating loss was $18.9 million higher in 2019 due mainly to total impairment charges of $22.5 million for goodwill and long-lived assets held for sale, partially offset by $1.4 million in lower depreciation and amortization expense.
Southern
Revenues for the Southern division decreased during the year ended December 31, 2019 as compared to the year ended December 31, 2018 due to three primary factors: a $2.1 million decrease in revenue due to management’s decision to exit the Eagle Ford shale area in 2018, a $1.9 million decrease in pipeline revenue and a $1.1 million decline in trucking revenue. In the Southern division, despite the overall decline in revenue due to pricing pressures, the volume of water transported by our pipeline increased in 2019 driven by a number of new customers acquired to replace the loss of a sizable customer’s pipeline volumes. The volumes from this particular customer largely ceased in May 2019. Disposal revenue was effectively flat with pricing decreases negating the slight increase in volumes. Trucking total billed hours were down approximately 24% in 2019 and revenue decreased $1.1 million due to overall lower customer activity in the region. During 2019, natural gas prices, as measured by the Henry Hub Natural Gas index, decreased 36% from $3.25 in 2018 to $2.09 in 2019, leading to a rig count reduction of 15% in the Southern operating area from 62 in 2018 to 53 in 2019.
In the Southern division, direct operating costs decreased during the year ended December 31, 2019 as compared to the year ended December 31, 2018 with direct operating costs as a percentage of revenue improving to 66.0% in 2019 as compared to 74.1% in the prior year period due to an increase in higher margin disposal services relative to trucking services. Operating loss improved by $6.2 million over the prior year period due to $5.5 million in restructuring and impairment charges during the year ended December 31, 2018 in connection with the Eagle Ford exit, while goodwill impairment charges were $2.7 million in 2019. Additionally, there was $3.0 million in lower depreciation and amortization expense in 2019.
Corporate/Other
The costs associated with the Corporate/Other division are primarily general and administrative costs. The Corporate general and administrative costs for the year ended December 31, 2019 were $16.8 million lower than those reported for the year ended December 31, 2018 due primarily to $15.3 million in compensation costs related to the departure of our former Chief Executive Officer and Chief Financial Officer during 2018. Operating loss for the Corporate division improved by $17.2 million due to the aforementioned compensation cost reduction and $0.3 million in non-recurring impairment charges in the prior year period.
Liquidity and Capital Resources
Cash Flows and Liquidity
Our consolidated financial statements have been prepared assuming that we will continue as a going concern, which contemplates continuity of operations, realization of assets, and liquidation of liabilities in the normal course of business. Our primary sources of capital for 2020 included cash generated by our operations and asset sales, our credit facilities, our Paycheck Protection Program loan, a comprehensive refinancing of the majority of the Company’s debt on November 16, 2020 with a commercial bank, and the proceeds received on January 2, 2019 from our 2018 Rights Offering (as defined below). During the years ended December 31, 2020 and December 31, 2019, cash provided by operating activities was $13.2 million and $6.5 million, respectively, and losses from continuing operations were $44.1 million and $54.9 million, respectively. As of December 31, 2020, our total indebtedness was $35.0 million and total liquidity was $17.9 million, consisting of $12.9 million of cash and $5.0 million available under the Operating LOC Loan (as defined below).
On November 16, 2020, the Company entered into a Loan Agreement (the “Master Loan Agreement”) with First International Bank & Trust, a North Dakota banking corporation (“Lender”). Pursuant to the Master Loan Agreement, Lender agreed to extend to the Company: (i) the “Equipment Loan”; (ii) a $10.0 million real estate term loan (the “CRE Loan”); (iii) a $5.0 million operating line of credit (the “Operating LOC Loan”); and (iv) a $4.839 million letter of credit facility (the “Letter of Credit Facility”) (the CRE Loan, the Equipment Loan, the Operating LOC Loan and the Letter of Credit Facility, collectively may be referred to as the “Loans”). The Loans were funded and closed on November 20, 2020. In connection with the closing of the Loans, the Company repaid all outstanding obligations in full under the First Lien Credit Agreement (as defined below) and the Second Lien Term Loan Agreement (as defined below) totaling $12.6 million and $8.3 million, respectively.
The Company continues to incur operating losses, and we anticipate losses to continue into the near future. Additionally, due to the COVID-19 outbreak, there has been a significant decline in oil and natural gas demand, which has negatively impacted our customers’ demand for our services, resulting in uncertainty surrounding the potential impact on our cash flows, results of operations and financial condition. We expect demand for oilfield services to be curtailed for the foreseeable future as we anticipate our customers’ crude oil or natural gas drilling and completion activity to continue to operate at lower levels.
In order to mitigate these conditions, the Company implemented various initiatives during 2020 that management believes positively impacted our operations, including personnel and salary reductions, other changes to our operating structure to achieve additional cost reductions, and the sale of certain assets. We believe that as a result of the cost reduction initiatives, our cash flow from operations, together with cash on hand and other available liquidity, will provide sufficient liquidity to fund operations for at least the next twelve months.
The following table summarizes our sources and uses of cash, cash equivalents and restricted cash for the years ended December 31, 2020, 2019 and 2018 (in thousands):
Year Ended December 31,
Net cash provided by (used in): 2020 2019 2018
Operating activities $ 13,165 $ 6,519 $ 9,449
Investing activities (165) (1,264) (35,318)
Financing activities (3,010) (7,503) 27,043
Change in cash, cash equivalents and restricted cash $ 9,990 $ (2,248) $ 1,174
Operating Activities
Net cash provided by operating activities was $13.2 million for the year ended December 31, 2020. The net loss, after adjustments for non-cash items, provided cash and restricted cash of $1.2 million in 2020 as compared to $12.1 million in 2019, as described below. Changes in operating assets and liabilities provided $12.0 million primarily due to a decrease of accounts receivable of $11.2 million. The non-cash items and other adjustments included $28.6 million of depreciation and amortization expense, long-lived asset impairment charges of $15.6 million, stock-based compensation expense of $2.0 million partially offset by a $1.6 million gain on the sale of assets.
Net cash provided by operating activities was $6.5 million for the year ended December 31, 2019. The net loss, after adjustments for non-cash items, provided cash and restricted cash of $12.1 million in 2019 as compared to $3.9 million in 2018, as described below. Changes in operating assets and liabilities used $5.6 million primarily due to a decrease in accounts payable and accrued and other current liabilities. The non-cash items and other adjustments included $36.2 million of depreciation and amortization expense, goodwill impairment charges of $29.5 million, stock-based compensation expense of $2.0 million, and long-lived asset impairment charges of $0.8 million partially offset by a $2.0 million gain on the sale of assets.
Net cash provided by operating activities was $9.4 million for the year ended December 31, 2018. The net loss, after adjustments for non-cash items, provided cash and restricted cash of $3.9 million. Changes in operating assets and liabilities provided $5.6 million primarily due to an increase in accounts payable and accrued liabilities, as well as a decrease in prepaid expenses and other receivables. The non-cash items and other adjustments included $46.4 million of depreciation and amortization expense, stock-based compensation expense of $12.7 million, $4.8 million for impairment of long-lived assets, and a $0.3 million change in deferred income taxes partially offset by a $0.9 million gain on the disposal of property, plant and equipment, a $0.4 million gain resulting from the change in the fair value of the derivative warrant liability, and bad debt recoveries of $0.3 million.
Investing Activities
Net cash used in investing activities was $0.2 million for the year ended December 31, 2020, and primarily consisted of $3.4 million for purchases of property, plant and equipment, offset by $3.2 million of proceeds from the sale of property, plant and equipment. Asset sales were primarily comprised of the disposition of two properties and under-utilized or non-core assets, while asset purchases included investments in our disposal capacity and our fleet upgrades for water transport and disposal services.
Net cash used in investing activities was $1.3 million for the year ended December 31, 2019, and primarily consisted of $8.2 million for purchases of property, plant and equipment, partially offset by $7.0 million of proceeds from the sale of property, plant and equipment. Asset sales were primarily comprised of under-utilized or non-core assets, while asset purchases included investments in our disposal capacity and our trucks for water transport and disposal services.
Net cash used in investing activities was $35.3 million for the year ended December 31, 2018, and consisted primarily of $42.3 million in cash paid for the acquisition of Clearwater (which is discussed further in Note 6 in the Notes to the Consolidated Financial Statements herein), $12.2 million for purchases of property, plant and equipment, partially offset by $19.1 million of proceeds from the sale of property, plant and equipment.
Financing Activities
Net cash used in financing activities was $3.0 million for the year ended December 31, 2020 and was primarily comprised of $27.0 million of payments on the First Lien Term Loan and Second Lien Term Loan, $2.0 million of payments on vehicle finance leases and other financing activities, partially offset by proceeds from the Equipment Loan of $13.0 million, the CRE Loan of $10.0 million and the PPP Loan (as defined below) of $4.0 million.
Net cash used in financing activities was $7.5 million for the year ended December 31, 2019 and was primarily comprised of $31.4 million in cash payments for the Bridge Term Loan, $4.9 million of payments on the First Lien Term Loan and Second Lien Term Loan, $2.2 million of payments on finance leases and other financing activities, partially offset by $31.1 million of proceeds received from the issuance of stock for the completed Rights Offering.
Net cash provided by financing activities was $27.0 million for the year ended December 31, 2018, and consisted of $32.5 million in proceeds from the Bridge Term Loan, $10.0 million in additional proceeds under the First Lien Term Loan, partially offset primarily by payments of $13.4 million on the First Lien Term Loan and Second Lien Term Loan and $1.9 million in payments under capital leases and other financing activities. The Bridge Term Loan proceeds were primarily related to the acquisition of Clearwater and were repaid on January 2, 2019 from the proceeds raised in the Rights Offering.
Capital Expenditures
Our capital expenditure program is subject to market conditions, including customer activity levels, commodity prices, industry capacity and specific customer needs. Cash required for capital expenditures for the year ended December 31, 2020 totaled $3.4 million compared to $8.2 million for the year ended December 31, 2019. These capital expenditures were partially offset by proceeds received from the sale of under-utilized or non-core assets of $3.2 million and $7.0 million in the years ended December 31, 2020 and 2019, respectively.
A portion of our transportation-related capital requirements are financed through finance leases (see Note 5 in the Notes to the Consolidated Financial Statements for further discussion of finance leases). We had $0.5 million and $9.5 million of equipment additions under finance leases during the years ended December 31, 2020 and 2019, respectively.
We continue to focus on improving the utilization of our existing assets and optimizing the allocation of resources in the various shale basins in which we operate. Due to the COVID-19 outbreak, we implemented a significant reduction in our capital expenditures budget for fiscal 2020, as discussed above in “Trends Affecting Our Operating Results.” Our planned capital expenditures for 2021 are expected to be financed through cash flow from operations, finance leases, borrowings under our Operating LOC Loan, or a combination of the foregoing.
Indebtedness
As of December 31, 2020, we had $35.0 million of indebtedness outstanding, consisting of $13.0 million under the Equipment Loan, $9.9 million under the CRE Loan, $4.0 million under the PPP Loan, $0.4 million under the Vehicle Term Loan (as defined below), $0.2 million under the Equipment Finance Loan (defined below), and $7.6 million of finance leases for vehicle financings and real property leases.
As further described below, the Loans contain certain affirmative and negative covenants, including a minimum debt service coverage ratio (“DSCR”), beginning December 31, 2021, as well as other terms and conditions that are customary for loans of this type. As of December 31, 2020, we were in compliance with all covenants.
Master Loan Agreement
On November 16, 2020, the Company entered into the Master Loan Agreement with Lender. Pursuant to the Master Loan Agreement, Lender agreed to extend to the Company: (i) the Equipment Loan that is subject to the MSPLF; (ii) the CRE Loan; (iii) the Operating LOC Loan; and (iv) the Letter of Credit Facility. On November 18, 2020, the Company was advised by Lender that the Equipment Loan had been approved as a MSPLF, and the Loans were funded and closed on November 20, 2020. In connection with the closing of the Loans, the Company repaid all outstanding obligations in full under the First Lien Credit Agreement and Second Lien Term Loan Agreement totaling $12.6 million and $8.3 million, respectively.
The terms of the Master Loan Agreement provide for customary events of default, including, among others, those relating to a failure to make payment, bankruptcy, breaches of representations and covenants, and the occurrence of certain events. Pursuant to the Master Loan Agreement, the Company must maintain a minimum DSCR of 1.35 to 1.00 beginning December 31, 2021 and annually on December 31 of each year thereafter. The DSCR means the ratio of (i) Adjusted EBITDA to (ii) the annual debt service obligations (less subordinated debt annual debt service) of the Company, calculated based on the actual four quarters ended on the applicable December 31 measurement date. If the DSCR falls below 1.35 to 1.00, then in addition to all other rights and remedies available to Lender, the interest rates on the CRE Loan, the Operating LOC Loan and the Letter of Credit Facility will increase by 1.5% until the minimum DSCR is maintained. The Company may cure a failure to comply with the DSCR by issuing equity interests in the Company for cash and applying the proceeds to the applicable Adjusted EBITDA measurement.
In addition, the Master Loan Agreement limits capital expenditures to $7.5 million annually and requires the Company to maintain a positive working capital position of at least $7.0 million at all times. The Master Loan Agreement also requires the Company deposit into a reserve account held by Lender (the “Reserve Account”) the sum of $2.5 million and make additional monthly deposits of $100 thousand into the Reserve Account. Funds held in the Reserve Account are not accessible by the Company and are pledged as additional security for the CRE Loan, the Operating LOC Loan and the Letter of Credit Facility.
Equipment Loan
The Equipment Loan is evidenced by that certain Promissory Note (Equipment Loan) executed by the Company in the original principal amount of $13.0 million. The Equipment Loan bears interest at a rate of one-month US dollar LIBOR plus 3.00%. Interest payments during the first year will be deferred and added to the loan balance and principal payments during the first two years will be deferred. Monthly amortization of principal will commence on December 1, 2022, with principal amortization payments due in annual installments of 15% on November 16, 2023, 15% on November 16, 2024, and the remaining 70% on the maturity date of November 16, 2025. The Equipment Loan, plus accrued and unpaid interest, may be prepaid at any time at par. The entire outstanding principal balance of the Equipment Loan together with all accrued and unpaid interest is due and payable in full on November 16, 2025. In connection with the Equipment Loan, the Company paid a $130 thousand origination fee to Lender and a $130 thousand origination fee to MSPLF.
The Equipment Loan includes all covenants and certifications required by the MSPLF, including, without limitation, the MSPLF Borrower Certifications and Covenants Instructions and Guidance. In connection with the same, the Company delivered a Borrower Certifications and Covenants (the “MS Certifications and Covenants”) to MS Facilities LLC, a Delaware limited liability company, a special purpose vehicle of the Federal Reserve. Under the MS Certifications and Covenants, the Company is subject to certain restrictive covenants during the period that the Equipment Loan is outstanding and, with respect to certain of those restrictive covenants, for an additional one year period after the Equipment Loan is repaid, including restrictions on the Company’s ability to repurchase stock, pay dividends or make other distributions and limitations on executive compensation and severance arrangements. The Equipment Loan is secured by a first lien security interest in all equipment and titled vehicles of the Company and its subsidiaries.
CRE Loan
The CRE Loan is evidenced by that certain Promissory Note (Real Estate) executed by the Company in the original principal amount of $10.0 million. The CRE Loan bears interest at the Federal Home Loan Bank Rate of Des Moines three-year advance rate plus 4.50% with an interest rate floor of 6.50%. The CRE Loan has a twelve-year maturity. The Company is required to make monthly principal and interest payments, and monthly escrow deposits for real estate taxes and insurance. The entire outstanding principal balance of the CRE Loan together with all accrued and unpaid interest is due and payable in full on November 13, 2032. In connection with the CRE Loan, the Company paid a $150 thousand origination fee to Lender.
The CRE Loan is secured by a first lien real estate mortgage on certain real estate owned by the Company and its subsidiaries and by the Reserve Account. The Company will incur a declining prepayment premium of 6%, 5%, 4%, 3%, 2%, and 1% of the outstanding principal balance of the CRE Loan over the first six years of the loan, respectively. The Company is not permitted to prepay the principal of the CRE Loan more than 5% per year without Lender’s prior written approval.
Operating LOC Loan
The Operating LOC Loan is evidenced by that certain Revolving Promissory Note (Operating Line of Credit Loan) executed by the Company in the original maximum principal amount of $5.0 million. The Operating LOC Loan bears interest at a variable rate, adjusting daily, equal to the Prime Rate plus 3.75%, with an interest rate floor of 7.00%. In connection with the Operating LOC Loan, the Company paid a $50 thousand origination fee to Lender. The Operating LOC Loan is currently undrawn and fully available to the Company.
The Operating LOC Loan is secured by a first lien security interest in all business assets of the Company and its subsidiaries, including without limitation all accounts receivable, inventory, trademarks and intellectual property licenses to which it is a party and by the Reserve Account. The entire outstanding principal balance of the Operating LOC Loan together with all accrued and unpaid interest is due and payable in full on November 14, 2021.
Letter of Credit Facility
The Letter of Credit Facility provides for the issuance of letters of credit of up to $4.839 million in aggregate face amount and is evidenced by that certain Promissory Note (Letter of Credit Loan) executed by the Company. Amounts drawn on letters of credit issued under the Letter of Credit Facility bear interest at a variable rate, adjusting daily, equal to the Prime Rate plus 3.75%, with an interest rate floor of 7.00%. The Letter of Credit Facility has a one-year final maturity on November 19, 2021.
On January 25, 2021, the Letter of Credit Facility was amended in order to increase by $510,000 the maximum availability thereunder. As amended, the Letter of Credit Facility provides for the issuance of letters of credit of up to $5.349 million in aggregate face amount and is evidenced by that certain Amended and Restated Promissory Note (Letter of Credit Loan), dated January 25, 2021, executed by the Company.
In connection with the Letter of Credit Facility, the Company is required to pay an annual fee equal to 3.00% of the maximum undrawn face amount of each letter of credit issued thereunder. The Letter of Credit Facility is secured by a first lien security interest in all business assets of the Company and its subsidiaries and by the Reserve Account.
First Lien Credit Agreement
On the Effective Date, pursuant to the Plan, the Company entered into a $45.0 million First Lien Credit Agreement (the “First Lien Credit Agreement”) by and among the lenders party thereto (the “First Lien Credit Agreement Lenders”), ACF FinCo I, LP, as administrative agent (the “Credit Agreement Agent”), and the Company, which included a $30.0 million senior secured revolving credit facility (the “Revolving Facility”) and a $15.0 million senior secured term loan facility (the “First Lien Term Loan”). The First Lien Credit Agreement also contained an accordion feature that provided for an increase in availability of up to an additional $20.0 million, subject to the satisfaction of certain terms and conditions contained in the First Lien Credit Agreement.
On October 5, 2018, in connection with the Clearwater Acquisition, we entered into a First Amendment to the Credit Agreement (the “First Amendment to the Credit Agreement”) with the First Lien Credit Agreement Lenders and the Credit Agreement Agent, which amended the First Lien Credit Agreement. Pursuant to the First Amendment to the Credit Agreement, the Credit Agreement Lenders provided us with an additional term loan under the First Lien Credit Agreement in the amount of $10.0 million, which was used to finance a portion of the Clearwater Acquisition.
On July 13, 2020, the Company entered into the Third Amendment to First Lien Credit Agreement (the “Third Amendment to First Lien Credit Agreement”) with the First Lien Credit Agreement Lenders and Credit Agreement Agent, which further amended the First Lien Credit Agreement to extend the maturity date from February 7, 2021 to May 15, 2022. In connection with the Third Amendment to First Lien Credit Amendment, on July 13, 2020, the Company repaid $2.5 million of the outstanding principal amount of the First Lien Term Loan.
On November 20, 2020, in connection with the closing of the Loans, all amounts outstanding under the First Lien Term Loan totaling $12.6 million were repaid in full, and all of the commitments and obligations under the First Lien Credit Agreement were terminated.
The Company made a liquidated damages payment in the amount of $0.5 million and paid a deferred amendment fee of $325 thousand as a result of the repayment of indebtedness and termination of the First Lien Credit Agreement. The Company also deposited approximately $5.1 million as cash collateral to secure outstanding letters of credit, which will be released and refunded to the Company upon cancellation of such outstanding letters of credit as replacements are issued under the Letter of Credit Facility. In connection with the repayment of outstanding indebtedness by the Company, the Company was permanently released from all security interests, mortgages, liens and encumbrances under the First Lien Credit Agreement.
Second Lien Term Loan Credit Agreement
On the Effective Date, pursuant to the Plan, the Company also entered into the Second Lien Term Loan Agreement (the “Second Lien Term Loan Agreement”) by and among the lenders party thereto (the “Second Lien Term Loan Lenders”), Wilmington, and the Company. Pursuant to the Second Lien Term Loan Agreement, the Second Lien Term Loan Lenders agreed to extend to the Company a $26.8 million second lien term loan facility (the “Second Lien Term Loan”), of which $21.1 million was advanced on the Effective Date and up to an additional $5.7 million was available at the request of the Company after the closing date subject to the satisfaction of certain terms and conditions specified in the Second Lien Term Loan Agreement.
On July 13, 2020, the Company entered into a Second Amendment to Credit Agreement with the lenders party thereto and Wilmington, which amended the Second Lien Term Loan Credit Agreement to extend the maturity date from October 7, 2021 to November 15, 2022.
On November 20, 2020, in connection with the closing of the Loans, all amounts outstanding under the Second Lien Term Loan Agreement totaling $8.3 million were repaid in full, and all of the commitments and obligations under the Second Lien Term Loan Agreement were terminated. The Company did not incur any early termination penalties as a result of the repayment of indebtedness and termination of the Second Lien Term Loan Agreement. In connection with the repayment of outstanding indebtedness by the Company, the Company was permanently released from all security interests, mortgages, liens and encumbrances under the Second Lien Term Loan Credit Agreement.
Paycheck Protection Program Loan
On May 8, 2020, pursuant to the Paycheck Protection Program (the “PPP”) under the Coronavirus Aid, Relief, and Economic Security Act (the “CARES Act”) enacted on March 27, 2020, an indirect wholly-owned subsidiary of the Company (the “PPP Borrower”) received proceeds of a loan (the “PPP Loan”) from First International Bank & Trust (the “PPP Lender”) in the principal amount of $4.0 million. The PPP Loan is evidenced by a promissory note (the “Promissory Note”), dated May 8, 2020. The Promissory Note is unsecured, matures on May 8, 2022, bears interest at a rate of 1.00% per annum, and is subject to the terms and conditions applicable to loans administered by the U.S. Small Business Administration (the “SBA”) under the CARES Act.
Under the terms of the PPP, up to the entire principal amount of the PPP Loan, and accrued interest, may be forgiven if the proceeds are used for certain qualifying expenses over the covered period as described in the CARES Act and applicable implementing guidance issued by the SBA, subject to potential reduction based on the level of full-time employees maintained by the organization during the covered period as compared to a baseline period.
In June 2020, the Paycheck Protection Program Flexibility Act of 2020 (“Flexibility Act”) was signed into law, which amended the CARES Act. The Flexibility Act changed key provisions of the PPP, including, but not limited to, (i) provisions relating to the maturity of PPP loans, (ii) the deferral period covering PPP loan payments and (iii) the process for measurement of loan forgiveness. More specifically, the Flexibility Act provides a minimum maturity of five years for all PPP loans made on or after the date of the enactment of the Flexibility Act (“June 5, 2020”) and permits lenders and borrowers to extend the maturity date of earlier PPP loans by mutual agreement. As of the date of this filing, the Company has not approached the PPP Lender to request an extension of the maturity date from two years to five years. The Flexibility Act also provides that if a borrower does not apply for forgiveness of a loan within 10 months after the last day of the measurement period (“covered period”), the PPP loan is no longer deferred and the borrower must begin paying principal and interest. In addition, the Flexibility Act extended the length of the covered period from eight weeks to 24 weeks from receipt of proceeds, while allowing borrowers that received PPP loans before June 5, 2020 to determine, at their sole discretion, a covered period of either eight weeks or 24 weeks.
The PPP Borrower used the PPP Loan proceeds for designated qualifying expenses over the covered period and applied for forgiveness of the PPP Loan during September 2020 in accordance with the terms of the PPP, but no assurance can be given that the PPP Borrower will obtain forgiveness of the PPP Loan in whole or in part. As such, the Company has classified the PPP loan as debt and it is included in long-term debt on the consolidated balance sheet.
With respect to any portion of the PPP Loan that is not forgiven, the PPP Loan will be subject to customary provisions for a loan of this type, including customary events of default relating to, among other things, payment defaults, breaches of the provisions of the Promissory Note and cross-defaults on any other loan with the PPP Lender or other creditors. Upon a default under the Promissory Note, including the non-payment of principal or interest when due, the obligations of the PPP Borrower thereunder may be accelerated. In the event the PPP Loan is not forgiven, the principal amount of $4.0 million shall be repaid at maturity.
The Company obtained the consent of the lenders under each of the First Lien Credit Agreement and the Second Lien Term Loan Credit Agreement for the PPP Borrower to enter into and obtain the funds provided by the PPP Loan.
Vehicle Term Loan
On December 27, 2019, we entered into a Direct Loan Security Agreement (the “Vehicle Term Loan”) with PACCAR Financial Corp as the Secured Party. The Vehicle Term Loan was used to refinance 38 trucks that were previously recorded as finance leases with balloon payments that would have been due in January of 2020. The Vehicle Term Loan matures on December 27, 2021, when the entire unpaid principal balance and interest, plus any other accrued charges, shall become due and payable. The Vehicle Term Loan shall be repaid in installments of $31,879 beginning on January 27, 2020 and on the same day of each month thereafter, with interest accruing at an annual rate of 5.27%.
Equipment Finance Loan
On November 20, 2019, we entered into a Retail Installment Contract (the “Equipment Finance Loan”) with a secured party to finance $0.2 million of equipment. The Equipment Finance Loan matures on November 15, 2022, and shall be repaid in monthly installments of approximately $7 thousand beginning December 2019 and then each month thereafter, with interest accruing at an annual rate of 6.50%.
Off Balance Sheet Arrangements
As of December 31, 2020, we did not have any material off-balance-sheet arrangements as defined in Item 303(a)(4)(ii) of SEC Regulation S-K.
Critical Accounting Policies and Estimates
Our discussion and analysis of financial condition and results of operations are based upon our audited consolidated financial statements, which have been prepared in accordance with generally accepted accounting principles in the United States (“GAAP”). The preparation of these financial statements requires management to make estimates and judgments that affect the reported amounts in the consolidated financial statements and accompanying notes. Actual results, however, may materially differ from our calculated estimates.
We believe the following critical accounting policies affect the more significant judgments and estimates used in the preparation of our financial statements and changes in these judgments and estimates may impact future results of operations and financial condition. For additional discussion of our accounting policies see Note 3 in the Notes to the Consolidated Financial Statements included in this Annual Report on Form 10-K.
Allowance for Doubtful Accounts
Accounts receivable are recognized and carried at the original invoice amount less an allowance for doubtful accounts. We provide an allowance for doubtful accounts to reflect the expected uncollectibility of trade receivables for both billed and unbilled receivables on our service and rental revenues. We perform ongoing credit evaluations of prospective and existing customers and adjust credit limits based upon payment history and the customer’s current credit worthiness, as determined by a review of their current credit information. In addition, we continuously monitor collections and payments from customers and maintain a provision for estimated credit losses based upon historical experience and any specific customer collection issues that have been identified. Inherent in the assessment of the allowance for doubtful accounts are certain judgments and estimates including, among others, the customer’s willingness or ability to pay, our compliance with customer invoicing requirements, the effect of general economic conditions and the ongoing relationship with the customer. Additionally, if the financial condition of a specific customer or our general customer base were to deteriorate, resulting in an impairment of their ability to make payments, additional allowances may be required. Accounts receivable are presented net of allowances for doubtful accounts of approximately $1.0 million, $1.3 million, and $1.6 million at December 31, 2020, 2019 and 2018, respectively.
Impairment of Goodwill
Our goodwill was tested for impairment annually at October 1st and more frequently if events or circumstances lead to a determination that it was more likely than not that the fair value of a reporting unit is less than its carrying amount. If after assessing the totality of events or circumstances, an entity determined it was not more likely than not that the fair value of a reporting unit is less than its carrying amount, then performing the impairment test was unnecessary. In the event a determination was made that it was more likely than not that the fair value of a reporting unit was less than its carrying value, the goodwill impairment test was performed. The first step of the test, used to identify potential impairment, compared the estimated fair value of a reporting unit with its carrying amount, including goodwill. If the fair value of a reporting unit exceeds its carrying amount, goodwill of the reporting unit was not considered to be impaired. If the carrying amount of a reporting unit exceeded its fair value, since we adopted ASU No. 2017-04, Intangibles - Goodwill and Other (Topic 350) - Simplifying the Test for Goodwill Impairment, an impairment charge was recorded based on the excess of a reporting unit’s carrying amount over its fair value.
When we reviewed goodwill for impairment as of October 1, 2019, we determined that it was more likely than not that the fair value of the reporting units were less than their carrying value. As a result, we completed the goodwill impairment test and determined that the fair value of all three reporting units was less than the carrying amount, resulting in a goodwill impairment charge of $29.5 million during the year ended December 31, 2019. See Note 8 for further details on the goodwill impairment during 2019.
Impairment of Long-Lived Assets and Intangible Assets with Finite Useful Lives
We review long-lived assets including intangible assets with finite useful lives for impairment whenever events or changes in circumstances indicate the carrying value of a long-lived asset (or asset group) may not be recoverable. If an impairment indicator is present, we evaluate recoverability by comparing the estimated future cash flows of the asset group, on an undiscounted basis, to their carrying values. The asset group represents the lowest level for which identifiable cash flows are largely independent of the cash flows of other groups of assets and liabilities. If the undiscounted cash flows exceed the carrying value, no impairment is present. If the undiscounted cash flows are less than the carrying value, the impairment is measured as the difference between the carrying value and the fair value of the long-lived asset (or asset group). Our determination that an event or change in circumstance has occurred potentially indicating the carrying amount of an asset (or asset group) may not be recoverable generally includes but is not limited to one or more of the following: (1) a deterioration in an asset’s financial performance compared to historical results, (2) a shortfall in an asset’s financial performance compared to forecasted results, (3) changes affecting the utility and estimated future demands for the asset, (4) a significant decrease in the market price of an asset, (5) a current expectation that a long-lived asset will be sold or disposed of significantly before the end of its previously estimated useful life, (6) a significant adverse change in the extent or manner in which a long-lived asset (asset group) is being used or in its physical condition, and (7) declining operations and severe changes in projected cash flows.
We recorded total impairment charges of $15.6 million, $0.8 million and $4.8 million for long-lived assets during the years ended December 31, 2020, 2019 and 2018, respectively, which was included in “Impairment of long-lived assets” in the consolidated statement of operations. Of the impairment charges recorded during the year ended December 31, 2020, $15.0 million related to long-lived assets and $0.6 million related to long-lived assets classified as held for sale. All of the impairment charges recorded during 2019 and 2018 were related to long-lived assets classified as held for sale. We could recognize future impairments to the extent adverse events or changes in circumstances result in conditions in which long-lived assets are not recoverable. See Note 8 in the Notes to the Consolidated Financial Statements for additional information on our impairment charges.
Income Taxes and Valuation of Deferred Tax Assets
We are subject to federal income taxes and state income taxes in those jurisdictions in which we operate. We exercise judgment with regard to income taxes in interpreting whether expenses are deductible in accordance with federal income tax and state income tax codes, estimating annual effective federal and state income tax rates and assessing whether deferred tax assets are, more likely than not, expected to be realized. The accuracy of these judgments impacts the amount of income tax expense we recognize each period.
With regard to the valuation of deferred tax assets, we record valuation allowances to reduce net deferred tax assets to the amount considered more likely than not to be realized. All available evidence is considered to determine whether, based on the weight of that evidence, a valuation allowance for deferred tax assets is needed. See Note 19 to our Consolidated Financial Statements herein for further information regarding the valuation of our deferred tax assets and the impact of new legislation.
Future realization of the tax benefit of an existing deductible temporary difference or carryforward ultimately depends on the existence of sufficient taxable income of the appropriate character (for example ordinary income or capital gain) within the carryback or carryforward periods available under the tax law. We have had significant pretax losses in recent years. Accordingly, we do not have income in carryback years. These cumulative losses also present significant negative evidence about the likelihood of income in carryforward periods.
Future reversals of existing taxable temporary differences are another source of taxable income that is used in this analysis. As a result, deferred tax liabilities in excess of deferred tax assets generally will provide support for recognition of deferred tax assets. However, most of our deferred tax assets are associated with net operating loss (“NOL”) carryforwards, many of which statutorily expire after a specified number of years; therefore, we compare the estimated timing of these taxable timing difference reversals with the scheduled expiration of our NOL carryforwards, considering any limitations on use of NOL carryforwards, and record a valuation allowance against deferred tax assets for which realization is not more likely than not. In addition, as a result of limitations on the use of our NOLs due to prior ownership changes, we have reduced our deferred tax asset and corresponding valuation allowance by the NOLs that will likely expire unused.
As a matter of law, we are subject to examination by federal and state taxing authorities. We have estimated and provided for income taxes in accordance with settlements reached with the Internal Revenue Service in prior audits. Although we believe that the amounts reflected in our tax returns substantially comply with the applicable federal and state tax regulations, both the IRS and the various state taxing authorities can take positions contrary to our position based on their interpretation of the law. A tax position that is challenged by a taxing authority could result in an adjustment to our income tax liabilities and related tax provision.
We measure and record tax contingency accruals in accordance with GAAP which prescribes a threshold for the financial statement recognition and measurement of a tax position taken or expected to be taken in a return. Only positions meeting the “more likely than not” recognition threshold at the effective date may be recognized or continue to be recognized. A tax position is measured at the largest amount that is greater than 50% likely of being realized upon ultimate settlement.
Revenue Recognition
On January 1, 2018, we adopted the guidance in ASC 606, including all related amendments, and applied the new revenue standard to all contracts using the modified retrospective method. The impact of the new revenue standard was not material and there was no adjustment required to the opening balance of retained earnings. The comparative information has not been restated and continues to be reported under ASC 605, or the accounting guidance in effect for those periods.
Revenues are generated upon the performance of contracted services under formal and informal contracts with customers. Revenues are recognized when the contracted services for our customers are completed in an amount that reflects the consideration we expect to be entitled to in exchange for those services. Sales and usage-based taxes are excluded from revenues. Payment is due when the contracted services are completed in accordance with the payment terms established with each customer prior to providing any services. As such, there is no significant financing component for any of our revenues.
Some of our contracts with customers involve multiple performance obligations as we are providing more than one service under the same contract, such as water transport services and disposal services. However, our core service offerings are capable of being distinct and also are distinct within the context of contracts with our customers. As such, these services represent separate performance obligations when included in a single contract. We have standalone pricing for all of our services which is negotiated with each of our customers in advance of providing the service. The contract consideration is allocated to the individual performance obligations based upon the standalone selling price of each service, and no discount is offered for a bundled services offering.
Environmental and Legal Contingencies
We have established liabilities for environmental and legal contingencies. We record a loss contingency for these matters when it is probable that a liability has been incurred and the amount of the loss can be reasonably estimated. In determining the liability, we consider a number of factors including, but not limited to, the jurisdiction of the claim, related claims, insurance coverage when insurance covers the type of claim and our historic outcomes in similar matters, if applicable. We are primarily self-insured against physical damage to our property, equipment and vehicles due to large deductibles or self-insurance. We are also self-insured for certain potential liabilities for third-party vehicular claims. A significant amount of judgment and the use of estimates are required to quantify our ultimate exposure in these matters, and the actual outcome could differ significantly from estimated amounts. The determination of liabilities for these contingencies is reviewed periodically to ensure that we have accrued the proper level of expense. The liability balances are adjusted to account for changes in circumstances for ongoing issues, including the effect of any applicable insurance coverage for these matters. While we believe that the amount accrued is adequate, future changes in circumstances, or in our assumptions or estimates, could impact these determinations or have a negative impact on our reported financial results.
Asset Retirement Obligations
We record obligations to retire tangible, long-lived assets on our balance sheet as liabilities, which are recorded at a discount when we incur the liability. A certain amount of judgment is involved in estimating the future cash flows of such obligations, as well as the timing of these cash flows. If our assumptions and estimates on the amount or timing of the future cash flows change, it could potentially have a negative impact on our earnings.
Recently Issued Accounting Pronouncements
See the “Recently Issued Accounting Pronouncements” section of Note 3 on Significant Accounting Policies in the Notes to the Consolidated Financial Statements herein for a complete description of recent accounting standards which may be applicable to our operations. The significant accounting standards that have been adopted during the year ended December 31, 2020 are described in Note 3 on Significant Accounting Policies in the Notes to the Consolidated Financial Statements herein.

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Item 7A. Quantitative and Qualitative Disclosures about Market Risk
Inflation
Inflationary factors, such as increases in our cost structure, could impair our operating results. Although we do not believe that inflation has had a material impact on our financial position or results of operations to date, a high rate of inflation in the future may have an adverse effect on our ability to maintain current levels of gross margin and selling, general and administrative expenses as a percentage of sales revenue if the selling prices of our products do not increase with these increased costs.
Commodity Risk
We are subject to market risk exposures arising from declines in oil and natural gas drilling activity in unconventional areas, which is primarily a function of the market price for oil and natural gas. Various factors beyond our control affect the market prices for oil and natural gas, including but not limited to the level of consumer demand, governmental regulation, the price and availability of alternative fuels, oil supply conflicts, political instability in foreign markets, weather-related factors and the overall economic environment. Market prices for oil and natural gas historically have been volatile and unpredictable, and we expect this volatility to continue in the future. Prolonged declines in the market price of oil and/or natural gas could contribute to declines in drilling activity and accordingly would reduce demand for our services. We attempt to manage this risk by strategically aligning our assets with those areas where we believe demand is highest and market conditions for our services are most favorable. If there is further deterioration in our business operations or prospects, our stock price, the broader economy or our industry, including further declines in oil and natural gas prices, the value of our long-lived assets, or those we may acquire in the future, could decrease significantly and result in additional impairment and financial statement write-offs which could have a material adverse effect on our financial condition, results of operations and cash flows.
Interest Rates
As of December 31, 2020, no borrowings were outstanding under the Operating LOC Loan, while the outstanding principal balances on the Equipment Loan and CRE Loan were $13.0 million and $9.9 million, respectively. Interest on the Equipment Loan accrues at an annual rate equal to the LIBOR Rate plus 3.00%, and interest on the CRE Loan accrues at an annual rate equal to the Federal Home Loan Bank Rate of Des Moines three-year advance rate plus 4.50%, with an interest rate floor of 6.50%. The weighted average interest rate for the year ended December 31, 2020 was 7.0% for the Operating LOC Loan, 3.1% for the Equipment Loan, and 6.5% for the CRE Loan. We have assessed our exposure to changes in interest rates on variable rate debt by analyzing the sensitivity to our earnings assuming various changes in market interest rates. Assuming a hypothetical increase of 1% to the interest rates on the average outstanding balance of our variable rate debt portfolio during the year ended December 31, 2020, our net interest expense for year ended December 31, 2020 would have increased by an estimated $0.2 million.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Item 8. Financial Statements and Supplementary Data
The financial statements and supplementary data required by Regulation S-X are included in Item 15. “Exhibits, Financial Statement Schedules” contained in Part IV, Item 15 of this Annual Report on Form 10-K.

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.

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ITEM 9A. CONTROLS AND PROCEDURES
Item 9A. Controls and Procedures
Disclosure controls and procedures are controls and other procedures that are designed to ensure that information required to be disclosed in company reports filed or submitted under the Securities Exchange Act of 1934, as amended (the “Exchange Act”) is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the Securities and Exchange Commission, and that such information is accumulated and communicated to management, including our Chief Executive Officer and Interim Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.
Evaluation of Disclosure Controls and Procedures
An evaluation of the effectiveness of our disclosure controls and procedures was performed under the supervision of, and with the participation of, management, including our Chief Executive Officer and Interim Chief Financial Officer, as of the end of the period covered by this Annual Report on Form 10-K. Based on this evaluation, our Chief Executive Officer and Interim Chief Financial Officer concluded that our disclosure controls and procedures are effective.
Management’s Annual Report on Internal Control over Financial Reporting
The Company’s management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934. The Company’s internal control system is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the consolidated financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America.
The 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 consolidated financial statements in accordance with GAAP, 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 consolidated 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.
Management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2020. In making its assessment of internal control over financial reporting, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework (2013). Based on this assessment, management concluded that our internal control over financial reporting was effective as of December 31, 2020.
Due to our aggregate market value of the voting and non-voting common equity held by non-affiliates falling below $75.0 million as of June 30, 2020, and our corresponding status as a smaller reporting company, our independent registered public accounting firm, Moss Adams LLP, was not required to issue an audit report on the effectiveness of our internal control over financial reporting for the year ended December 31, 2020.
Changes in Internal Control over Financial Reporting
There were no changes in our internal control over financial reporting during the year ended December 31, 2020 that materially affected, or were reasonably likely to materially affect, our internal control over financial reporting.

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ITEM 9B. OTHER INFORMATION
Item 9B. Other Information
None.
PART III

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ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Item 10. Directors, Executive Officers and Corporate Governance
The information required by this item will be contained in, and is incorporated by reference to, the Definitive Proxy Statement for our 2021 Annual Meeting of Stockholders or a Form 10-K/A which, in either case, we will file with the Securities and Exchange Commission within 120 days after our fiscal year ended December 31, 2020.

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ITEM 11. EXECUTIVE COMPENSATION
Item 11. Executive Compensation
The information required by this item will be contained in, and is incorporated by reference to, the Definitive Proxy Statement for our 2021 Annual Meeting of Stockholders or a Form 10-K/A which, in either case, we will file with the Securities and Exchange Commission within 120 days after our fiscal year ended December 31, 2020.

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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
The information required by this item will be contained in, and is incorporated by reference to, the Definitive Proxy Statement for our 2021 Annual Meeting of Stockholders or a Form 10-K/A which, in either case, we will file with the Securities and Exchange Commission within 120 days after our fiscal year ended December 31, 2020.

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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Item 13. Certain Relationships and Related Transactions, and Director Independence
The information required by this item will be contained in, and is incorporated by reference to, the Definitive Proxy Statement for our 2021 Annual Meeting of Stockholders or a Form 10-K/A which, in either case, we will file with the Securities and Exchange Commission within 120 days after our fiscal year ended December 31, 2020.

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ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
Item 14. Principal Accounting Fees and Services
The information required by this item will be contained in, and is incorporated by reference to, the Definitive Proxy Statement for our 2021 Annual Meeting of Stockholders or a Form 10-K/A which, in either case, we will file with the Securities and Exchange Commission within 120 days after our fiscal year ended December 31, 2020.
PART IV

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ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
Item 15. Exhibits, Financial Statement Schedules
(a) The following documents are filed as part of this Annual Report on Form 10-K:
1. Audited Consolidated Financial Statements:
Page
Report of Independent Registered Public Accounting Firm
Consolidated Balance Sheets at December 31, 2020 and 2019
Consolidated Statements of Operations for the Years Ended December 31, 2020, 2019 and 2018
Consolidated Statements of Changes in Shareholders’ Equity for the Years Ended December 31, 2020, 2019 and 2018
Consolidated Statements of Cash Flows for the Years Ended December 31, 2020, 2019 and 2018
Notes to Consolidated Financial Statements
2. Financial Statement Schedules: All financial statement schedules have been omitted since they are not required, not applicable, or the information is otherwise included in the audited consolidated financial statements.
(b) The exhibits listed on the “Exhibit Index” set forth below are filed with this Annual Report on Form 10-K or incorporated by reference as set forth therein.
Exhibit Number Description
2.1 Debtors’ Amended Prepackaged Plans of Reorganization, dated June 23, 2017 (incorporated herein by reference to Exhibit 2.1 to the Company’s Current Report on Form 8-K filed with the SEC on July 23, 2017).
2.2 Findings of Fact, Conclusions of Law, and Order Approving the Debtors’ Prepackaged Plans of Reorganization, dated July 25, 2017 (incorporated herein by reference to Exhibit 99.1 to the Company’s Current Report on Form 8-K filed with the SEC on July 23, 2017).
3.1 Second Amended and Restated Certificate of Incorporation of Nuverra Environmental Solutions, Inc. (incorporated herein by reference to Exhibit 3.1 to the Company’s Registration Statement on Form 8-A filed with the SEC on August 8, 2017).
3.2 Third Amended and Restated Bylaws of Nuverra Environmental Solutions, Inc. (incorporated herein by reference to Exhibit 3.2 to the Company’s Registration Statement on Form 8-A filed with the SEC on August 8, 2017).
3.3 Certificate of Designations of Series A Junior Participating Preferred Stock of Nuverra Environmental Solutions, Inc. (incorporated herein by reference to Exhibit 3.1 to the Company’s Registration Statement on Form 8-A filed with the SEC on December 21, 2020).
4.1 Specimen Global Stock Certificate (incorporated herein by reference to Exhibit 4.1 to the Company’s Registration Statement on Form 8-A filed with the SEC on August 8, 2017).
4.2 Registration Rights Agreement, dated as of August 7, 2017, by and among Nuverra Environmental Solutions, Inc. and the holders party thereto (incorporated herein by reference to Exhibit 4.2 to the Company’s Registration Statement on Form 8-A filed with the SEC on August 8, 2017).
4.3 Specimen Warrant Certificate (incorporated herein by reference to Exhibit 4.3 to the Company’s Registration Statement on Form 8-A filed with the SEC on August 8, 2017).
4.4 Warrant Agreement, dated as of August 7, 2017, between Nuverra Environmental Solutions, Inc. and American Stock Transfer & Trust Company, LLC (incorporated herein by reference to Exhibit 4.4 to the Company’s Registration Statement on Form 8-A filed with the SEC on August 8, 2017).
4.5 Description of Registrant’s Securities (incorporated herein by reference to the Company’s Registration Statement on Form 8-A filed with the SEC on August 8, 2017).
Exhibit Number Description
4.6 Rights Agreement, dated as of December 21, 2020, between Nuverra Environmental Solutions, Inc. and American Stock Transfer & Trust Company, LLC, as Rights Agent (incorporated herein by reference to Exhibit 4.1 to the Company’s Registration Statement on Form 8-A filed with the SEC on December 21, 2020).
10.1 † Amended and Restated Employment Agreement, dated August 7, 2017, between Joseph M. Crabb and Nuverra Environmental Solutions, Inc. (incorporated herein by reference to Exhibit 10.9 to the Company’s Current Report on Form 8-K filed with the SEC on August 11, 2017).
10.2 † Nuverra Environmental Solutions, Inc. 2017 Long Term Incentive Plan (incorporated herein by reference to Exhibit 10.1 to Nuverra’s Current Report on Form 8-K filed with the SEC on February 23, 2018).
10.3 † Form of Notice of Grant of Performance Restricted Stock Units and Award Agreement (incorporated herein by reference to Exhibit 10.2 to Nuverra’s Current Report on Form 8-K filed with the SEC on February 23, 2018).
10.4 † Form of Notice of Grant of Time-Based Restricted Stock Units and Award Agreement (incorporated herein by reference to Exhibit 10.3 to Nuverra’s Current Report on Form 8-K filed with the SEC on February 23, 2018).
10.5 † CEO Notice of Grant of Performance Restricted Stock Units and Award Agreement (incorporated herein by reference to Exhibit 10.4 to Nuverra’s Current Report on Form 8-K filed with the SEC on February 23, 2018).
10.6 † CEO Notice of Grant of Time-Based Restricted Stock Units and Award Agreement (incorporated herein by reference to Exhibit 10.5 to Nuverra’s Current Report on Form 8-K filed with the SEC on February 23, 2018).
10.7 † 2018 Restricted Stock Plan for Directors (incorporated herein by reference to Exhibit 10.7 to Nuverra’s Current Report on Form 8-K filed with the SEC on February 23, 2018).
10.8 † Form of Restricted Stock Grant Agreement (incorporated herein by reference to Exhibit 10.8 to Nuverra’s Current Report on Form 8-K filed with the SEC on February 23, 2018).
10.9 † Employment Agreement dated June 18, 2018, between Nuverra Environmental Solutions, Inc. and Robert Fox (incorporated by reference to Exhibit 10.1 to Nuverra’s Current Report on Form 8-K filed with the SEC on June 21, 2018).
10.10 Equity Purchase Agreement, dated October 5, 2018, by and among the David Niederst Irrevocable Trust, Stillwater Seven, LLC and Nuverra Ohio Disposal LLC (incorporated by reference to Exhibit 10.1 to Nuverra’s Current Report on Form 8-K filed with the SEC on October 11, 2018).
10.11 Employment Agreement, dated November 19, 2018, between the Company and Charles K. Thompson (incorporated by reference to Exhibit 10.1 to Nuverra’s Current Report on Form 8-K filed with the SEC on November 21, 2018).
10.12 Employment Agreement, dated April 3, 2020, between the Company and Eric Bauer (incorporated by reference to Exhibit 10.1 to Nuverra’s Current Report on Form 8-K filed with the SEC on April 9, 2020).
10.13 Promissory Note, dated as of May 8, 2020, by Badlands Power Fuels, LLC in favor of First International Bank & Trust (incorporated by reference to Exhibit 10.1 to Nuverra’s Current Report on Form 8-K filed with the SEC on May 14, 2020).
10.14 First Amendment to Employment Agreement, dated April 6, 2020, between the Company and Charles K. Thompson (incorporated by reference to Exhibit 10.1 to Nuverra’s Form 10-Q filed with the SEC on August 11, 2020).
10.15 First Amendment to Employment Agreement, dated April 6, 2020, between the Company and Robert Fox (incorporated by reference to Exhibit 10.2 to Nuverra’s Form 10-Q filed with the SEC on August 11, 2020).
10.16 Loan Agreement, dated as of November 16, 2020, by and between the Company and First International Bank & Trust (incorporated by reference to Exhibit 10.1 to Nuverra’s Current Report on Form 8-K filed with the SEC on November 27, 2020).
Exhibit Number Description
10.17 † Promissory Note (Equipment Loan), dated as of November 16, 2020, executed by the Company in favor of First International Bank & Trust(incorporated by reference to Exhibit 10.2 to Nuverra’s Current Report on Form 8-K filed with the SEC on November 27, 2020).
10.18 † Borrower Certifications and Covenants, dated as of November 16, 2020, executed by the Company to MS Facilities LLC, a Delaware limited liability company, a special purpose vehicle of the Federal Reserve (incorporated by reference to Exhibit 10.3 to Nuverra’s Current Report on Form 8-K filed with the SEC on November 27, 2020).
10.19 Promissory Note (Real Estate), dated as of November 13, 2020, executed by the Company in favor of First International Bank & Trust (incorporated by reference to Exhibit 10.4 to Nuverra’s Current Report on Form 8-K filed with the SEC on November 27, 2020).
10.20 Revolving Promissory Note (Operating Line of Credit Loan), dated as of November 13, 2020, executed by the Company in favor of First International Bank & Trust (incorporated by reference to Exhibit 10.5 to Nuverra’s Current Report on Form 8-K filed with the SEC on November 27, 2020).
10.21 Promissory Note (Letter of Credit Loan), dated as of November 18, 2020, executed by the Company in favor of First International Bank & Trust (incorporated by reference to Exhibit 10.6 to Nuverra’s Current Report on Form 8-K filed with the SEC on November 27, 2020).
10.22 † Security Agreement, dated as of November 16, 2020, by and among the Company, the other debtors party thereto, and the First International Bank & Trust (incorporated by reference to Exhibit 10.7 to Nuverra’s Current Report on Form 8-K filed with the SEC on November 27, 2020).
10.23 † Guaranty, dated as of November 16, 2020, by and among the guarantors party thereto and the First International Bank & Trust (incorporated by reference to Exhibit 10.8 to Nuverra’s Current Report on Form 8-K filed with the SEC on November 27, 2020).
10.24 Indemnity Agreement, dated as of November 16, 2020, by and among the Company, the other indemnitors party thereto, and the First International Bank & Trust (incorporated by reference to Exhibit 10.9 to Nuverra’s Current Report on Form 8-K filed with the SEC on November 27, 2020).
10.25 Assignment of Salt Water Disposal Lease and Contracts, dated as of November 13, 2020, by and among the assignors party thereto and the First International Bank & Trust (incorporated by reference to Exhibit 10.10 to Nuverra’s Current Report on Form 8-K filed with the SEC on November 27, 2020).
10.26 Amendment to Employment Agreement (Charles K. Thompson) (incorporated by reference to Exhibit 10.1 to Nuverra’s Current Report on Form 8-K filed with the SEC on December 17, 2020).
10.27 Amendment to Employment Agreement (Eric Bauer) (incorporated by reference to Exhibit 10.2 to Nuverra’s Current Report on Form 8-K filed with the SEC on December 17, 2020).
21.1 * Subsidiaries of Nuverra Environmental Solutions, Inc.
23.1 * Consent of Moss Adams LLP
24.1 * Power of Attorney of Officers and Directors of the Company (set forth on the signature pages of this Form 10-K).
31.1 * Certification of Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2 * Certification of Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1 * Certification of CEO and CFO Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
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Exhibit Number Description
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* Filed herewith
† Compensatory plan, contract or arrangement in which directors or executive officers may participate