NCSM US Equity☆

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations



The following is a discussion and analysis of our financial condition and results of operations as of, and for, the periods presented. You should read the following discussion and analysis of our financial condition and results of operations together with the sections entitled Item 1A. “Risk Factors,” “—Cautionary Note Regarding Forward-Looking Statements,” Item 6. “Selected Historical Financial Data” and our consolidated financial statements and related notes thereto included elsewhere in this Form 10-K. This section and other parts of the Form 10-K contain forward-looking statements regarding the industry outlook, estimates and assumptions concerning events and financial and industry trends that may affect our future results of operations or financial condition and other non-historical statements. These forward-looking statements are subject to numerous risks and uncertainties, including but not limited to the risks and uncertainties described in “—Cautionary Note Regarding Forward-Looking Statements” and Item 1A. “Risk Factors.” Our actual results may differ materially from those contained in or implied by these forward-looking statements.



Overview



We are a leading provider of highly engineered products and support services that facilitate the optimization of oil and natural gas well completions and field development strategies. We provide our products and services primarily to E&P companies for use in onshore wells, predominantly wells that have been drilled with horizontal laterals in unconventional oil and natural gas formations. Our products and services are utilized in oil and natural gas basins throughout North America and in selected international markets, including Argentina, China, Russia, the Middle East and the North Sea. We provided our products and services to over 200 customers in 2020, including leading large independent oil and natural gas companies and major oil companies.



Our primary offering is our fracturing systems products and services, which enable efficient pinpoint stimulation: the process of individually stimulating each entry point into a formation targeted by an oil or natural gas well. Our fracturing systems products and services are typically utilized in cemented wellbores and enable our customers to precisely place stimulation treatments in a more controlled and repeatable manner as compared with traditional completion techniques. Our fracturing systems products and services are utilized in conjunction with third-party providers of pressure pumping, coiled tubing and other services.



We own a 50% interest in Repeat Precision, which sells composite frac plugs and related products. We provide tracer diagnostics services for well completion and reservoir characterization that utilize downhole chemical and radioactive tracers. We sell products for well construction, including our AirLock casing buoyancy system, liner hanger systems and toe initiation sleeves. We operate in one reportable segment.



COVID-19 Impacts on the Oil & Gas Market and NCS Multistage



COVID-19, an infectious disease caused by severe acute respiratory syndrome coronavirus 2, has spread globally. The World Health Organization declared the COVID-19 outbreak a public health emergency of international concern on January 30, 2020 and a pandemic on March 11, 2020. According to Johns Hopkins University, as of February 28, 2021 there have been over 114 million confirmed cases, resulting in over 2.5 million deaths related to COVID-19 on a global basis.



Federal, state, provincial and local governments around the world have implemented measures designed to slow the spread of the coronavirus. These measures include, but are not limited to, quarantines, travel restrictions involving areas with large or growing confirmed case counts, school closures, social distancing guidelines intended to limit the size of group gatherings and maintain physical space between individuals and orders that workers in non-essential industries or roles work from home. In many countries, the most restrictive measures were eased throughout the second quarter, though case counts began rising during the third and fourth quarters in some areas, including several states in the U.S. and in Europe, following the relaxation of the restrictions. Several vaccines have been approved for use in the fourth quarter of 2020 and first quarter of 2021, with vaccination rates increasing through early 2021. However, several new variants of COVID-19 have emerged and vaccines approved to date have lower efficacy in combating some of these new variants. Accordingly, the uncertainty of the continued development, availability, distribution and acceptance of effective vaccines precludes any prediction as to the ultimate impact of COVID-19 on our business.



These measures and restrictions have had material impacts on the global economy, resulting in a significant reduction in global gross domestic product (“GDP”) in 2020 and continue to negatively impact GDP in early 2021. In addition, businesses have been forced to shut down, either temporarily or permanently, resulting in a significant growth in unemployment rates, which have partially declined, but remain at elevated levels by historical standards.



The demand for crude oil has been materially reduced as a result of the measures taken by governments around the world to mitigate the spread of COVID-19, primarily due to significant reductions in air and motor vehicle travel, which has reduced the demand for jet fuel, diesel and gasoline, the key refined products derived from crude oil. In its January 2021 Oil Market Report, the International Energy Agency (“IEA”) stated that demand for crude oil for the full year in 2020 contracted by 8.8 MMBBL/D as compared to 2019, as a result of COVID-19 case counts and the timing of and nature of global economic activity. In its February 2021

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Oil Market Report, IEA predicts that demand for crude oil will rise by 5.4 MMBBL/D in 2021 but the recovery depends on the resolution of the pandemic and impact of fiscal and monetary support packages. Even if demand increases to the level predicted by the IEA, this increase in projected 2021 demand would not offset the significant demand reduction of 2020, leaving 2021 demand 3.4 MMBBL/D below 2019 levels.



The significant reduction in global demand that began in early 2020 led to a decline in the average WTI crude oil price which was $27.96/BBL in the second quarter of 2020 before measures to restrict the spread of COVID-19 were put in place for most of the world. The average WTI crude oil price recovered to an average of $41.70/BBL over the third and fourth quarters of 2020 but remains volatile. In addition, oil storage in OECD countries remains at elevated levels and floating storage is being utilized to hold excess crude oil. Members of OPEC and certain other countries, including Russia (informally known as “OPEC+”), agreed to a collective reduction in oil production of 9.7 MMBBL/D in May through July of 2020, 7.7 MMBBL/D in August through December 2020 and approximately 7 MMBBL/D through at least the first few months of 2021. In addition, Saudi Arabia announced an additional supply reduction of 1.0 MMBBL/D in February and March 2021 due to demand concerns related to restrictions put in place in late 2020 as infections experienced a surge, in part due to the emergence of new virus variants, implying a total reduction in production by OPEC+ of approximately 8 MMBBL/D for those months. The intent of the voluntary supply reductions is to attempt to increase the realized price of crude oil, and more specifically to return global oil storage capacity to normal levels over time as the economy and oil demand recovers. Given the uncertainty related to the rate of new COVID-19 infections, vaccinations, economic recovery and oil demand recovery, OPEC+ plans to meet monthly during 2021 to evaluate potential increases or decreases to the targeted level of reduction in production.



As a result of the rapid and material reduction in oil pricing, E&P companies responded by significantly reducing their capital expenditure budgets for 2020, which resulted in significant reductions in drilling and completion activity. In North America, capital expenditures in 2020 were typically reduced by anywhere from 30% to nearly 100% less than the original E&P company capital budgets, with some only spending the capital required to safely operate their existing productive assets. Reductions in activity began in mid-to-late March and decreases in completions activity occurred faster than reductions to drilling activity, as completions equipment is typically contracted on a short-term basis, while drilling rigs may be contracted for several months or years. Many E&P companies partially shut in production in areas where the marginal cash operating cost exceeds the market price. The amount of shut-in capacity in North America is believed to have peaked in May, with the volume of shut-in production reducing over time. Initial 2021 budgets for E&P companies suggest a slight reduction from 2020 expenditures with an objective of generating free cash flow and maintaining production at late 2020 levels.



Low commodity prices have also impacted E&P companies that carry significant debt on their balance sheets and companies that rely on liquidity from loans that are based on the value of their oil and gas reserves. There have been numerous Chapter 11 bankruptcy filings by E&P companies, and the credit quality of the upstream oil and gas sector, our customer base, has been negatively impacted by the decline in market conditions, primarily related to the COVID-19 pandemic. We recorded a provision for doubtful accounts of $0.8 million during the year ended December 31, 2020. In addition, perceptions of the industry in which we operate, by investors and financial institutions, have reduced the availability of financing for ourcustomers and increased their cost of financing.



The factors mentioned above have led to an increase in consolidation amongst E&P companies, especially large, independent publicly-traded E&P companies. During late 2020, several large consolidation transactions were announced, including Chevron Corp’s acquisition of Noble Energy, ConocoPhillips’ acquisition of Concho Resources, Devon Energy’s merger with WPX Energy and Pioneer Natural Resources’ acquisition of Parsley Energy. These consolidation transactions allow the combined entities to reduce costs, in part due to economies of scale, and can lead to reduced capital spending on a pro forma basis than would have been spent had the transaction not occurred. NCS has provided products and services to several of the companies involved in consolidation transactions, and we have experienced a reduction in spending with certain customers and may continue to further experience a reduction in future business with consolidating customers if combined capital spending is reduced, if procurement strategies are altered, or if the counterparty in the consolidation has other preferred vendors for the products and services we have been providing.

The reduction in customer capital spending and responses as a result of a decline in market conditions primarily related to the COVID-19 pandemic began to impact NCS in March 2020. Customers in North America began to quickly reduce the number of active completions crews, travel restrictions began to impact international operations, and activity in certain regions, including Argentina and China, was shut down due to government actions to contain the spread of COVID-19. In addition, throughout the year customers further reduced their capital spending and the resulting drilling and completion activity, which reduced the level of demand for our products and services and the pricing we received for our products and services.



While we experienced modest disruptions to our supply chain as a result of the COVID-19 pandemic, including delays in importation of certain chemical products from China and temporary work-from-home orders that reduced the capacity at the Repeat Precision machine shop operations in Mexico, such disruptions were temporary in nature, the impacted products are available through alternative sources of supply and we maintained sufficient inventory on hand to meet customer demand. We have also experienced

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delays in access to certain materials and products utilized in our research and development activities, which has led, and may continue to lead, to delays in new product introductions.



In response to the current market conditions and reduction in demand for our products and services, including as a result of the COVID-19 pandemic, NCS has undertaken, and the Board of Directors monitored and evaluated, multiple initiatives to reduce our cost structure, limit capital expenditures and enhance our liquidity and access to capital, including:

· The decision to not pay 2019 or 2020 bonuses;

· A moratorium on non-essential travel for all employees;

· Negotiation of new rates, work rules and payment schedules with vendors;



NCS continues to evaluate market conditions and will continue to take necessary actions to further reduce our cost base and enhance liquidity should there be a further reduction in the demand for our products and services.



In connection with the reductions in force described above, NCS recorded severance expense of $5.7 million during the year ended December 31, 2020.



As a result of the decrease in crude oil pricing, customer capital spending plans and activity as a result of the decline in market conditions primarily related to the COVID-19 pandemic as well as the resulting decline in the quoted price of our common stock, we assessed the recoverability of the carrying value of our property and equipment and finite-lived intangible assets as of March 31, 2020 and determined that a triggering event had occurred. As a result of the analysis, we recorded impairment charges of $9.7 million in property and equipment and $40.5 million related to identifiable intangible assets, which we recorded during the first quarter of 2020. There were no impairment charges recorded on our property and equipment or identifiable intangible assets during the remainder of 2020. For additional information, see “Note 6. Property and Equipment” and “Note 7. Goodwill and Identifiable Intangibles” of our consolidated financial statements.



On August 6, 2020, we entered into an amendment to our Senior Secured Credit Facility which, among other changes, reduced the lender commitments in the U.S. under our Senior Secured Credit Facility to $25.0 million and further limited the amount we may borrow dependent on a borrowing base calculated based on eligible receivables, which does not include receivable balances at Repeat Precision. See —Liquidity and Capital Resources—Financing Arrangements for a description of the amendment. Our borrowing base under the Senior Secured Credit Facility as of December 31, 2020 was $11.0 million. The amount available to be drawn under the Senior Secured Credit Facility may decline from current levels due to reductions in our borrowing base or a springing financial covenant if our business continues to be adversely impacted by a decline in market conditions primarily related to the COVID-19 pandemic.



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See Item 1A. Risk Factors for a discussion of additional actual or potential impacts of the COVID-19 pandemic on our business and operations.



Outlook



Based on initial capital budgets for 2021 that have been set by E&P companies, we believe that industry drilling and completions activity in North America will be modestly lower in 2021 than it was in 2020. Many of our customers in North America committed to generating free cash flow while maintaining production at levels consistent with late 2020. Drilling activity in the U.S. declined sequentially throughout the first half of 2020 before bottoming in the third quarter and increasing in the fourth quarter of 2020 and in early 2021. Completions activity in the U.S. is also expected to increase slightly in the first quarter of 2021 as compared to the fourth quarter of 2020, however customer drilling and completion activity in the U.S. in the first quarter of 2021 was negatively impacted by winter storm Uri, which resulted in widespread, but temporary, production shut-ins, unsafe road conditions and other logistical challenges particularly in the Permian Basin and other areas in Texas and Oklahoma. We believe that the rig count in Canada in the second quarter of 2020 was at the lowest levels of the last 50 years and did not experience a material seasonal increase in the third quarter of 2020. The Canadian rig count recovered, but it remained well below seasonal averages in the fourth quarter of 2020. Similarly, the Canadian rig count has experienced the expected seasonal increase through the end of February 2021 but is approximately 25% below the same period of 2020. The low level of industry activity has led, and is expected to continue to lead, to intense competitive pressure across all of our product and service offerings in North America, which impacts our market share as well as our margins. We currently expect international industry activity to be approximately flat in 2021 as compared to 2020 with activity increasing through the year.



Market Conditions



Oil and Natural Gas Drilling and Completion Activity



Our products and services are primarily sold to North American E&P companies and our ability to generate revenues from our products and services depends upon oil and natural gas drilling and completion activity in North America. Oil and natural gas drilling and completion activity is directly related to oil and natural gas prices.



Oil and natural gas prices remain volatile, with WTI crude oil pricing at approximately $60 per barrel in December 2017, which fell to approximately $45 per barrel in December 2018, recovered to approximately $61 per barrel by the end of December 2019 and fell again to approximately $48 per barrel in December 2020. Crude oil pricing has historically been supported by voluntary oil production reductions by members of OPEC and OPEC +. In response to decreased demand related to the COVID-19 pandemic, OPEC + agreed to a collective reduction in oil production of 9.7 MMBBL/D in May through July of 2020, 7.7 MMBBL/D in August through December 2020 and approximately 7 MMBBL/D through at least the first few months of 2021. In addition, Saudi Arabia announced an additional voluntary supply reduction of 1.0 MMBBL/D in February and March 2021 due to demand concerns related to restrictions put in place in late 2020 as infections experienced a surge, in part due to the emergence of new virus variants, implying a reduction in production of approximately 8 MMBBL/D for those months. The intent of the voluntary supply reductions is to attempt to increase the realized price of crude oil, and more specifically to return global oil storage capacity to normal levels over time as the economy and oil demand recovers. Given the uncertainty related to the rate of new COVID-19 infections, vaccinations, economic recovery and oil demand recovery, OPEC+ plans to meet monthly during 2021 to evaluate potential increases or decreases to the targeted level of reduction in production.

On August 6, 2018, the United States announced its intent to impose economic sanctions on Iran, following the United States’ withdrawal from an international accord intended to limit Iran’s nuclear programs. The sanctions, including secondary sanctions targeting companies that do business with Iran, were intended to reduce Iran’s level of crude oil exports and went into effect in November 2018. Temporary waivers were granted to eight countries that import oil from Iran, but those waivers expired on May 2, 2019. The new administration in the U.S. has signaled that it may revisit the sanctions, which could result in an increase in exports from Iran, which could have a negative impact on oil prices.



Over the course of 2018, there was an increase in the difference between the benchmark crude oil pricing in certain markets and WTI, known in the industry as differentials. Crude oil in certain areas, including West Texas, North Dakota and Canada traded at a larger discount to WTI than in historical periods due to current and forecasted production levels that are in excess of local refining demand and pipeline capacity. In response to these price differentials, many E&P companies operating in these areas reduced their drilling and completion activity in the second half of 2018 and into 2019 or chose to delay completions until additional pipeline or rail capacity was placed into service. Differentials have since narrowed in North Dakota and West Texas. In Canada, the Province of Alberta implemented measures intended to reduce the differential in the region, including the implementation of mandatory production curtailments. These curtailments, which were in place for companies producing more than 20,000 barrels per day in the province (subject to certain exemptions) through December 2020, have since been lifted.



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Natural gas pricing was at an average level of $3.15 and $2.99 per MMBtu during 2018 and 2017, respectively, but fell to an average level of $2.56 per MMBtu during the year ended 2019 as supply growth exceeded demand growth. Natural gas pricing fell even further to an average level of $2.03 per MMBtu during the year ended 2020 as it has been negatively impacted by the COVID-19 pandemic and resulting market conditions. Realized natural gas prices for Canadian E&P customers are typically at a discount to U.S. Henry Hub pricing. Spot pricing for Canadian natural gas at the AECO hub has been volatile since mid-2017, with wide discounts to Henry Hub pricing resulting from infrastructure bottlenecks.



Sustained declines in commodity prices, or sustained periods when the local pricing received in regional markets is below benchmark pricing, known in the industry as high differentials, would be expected to lead North American E&P companies to further reduce drilling and completion activity, which could negatively impact our business.



Listed and depicted below are recent crude oil and natural gas pricing trends, as provided by the Energy Information Administration (“EIA”) of the U.S. Department of Energy:







 Average Price





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Listed and depicted below are the average number of operating onshore rigs in the U.S. and in Canada per quarter since the first quarter of 2016, as provided by Baker Hughes Company. The quarterly changes in the Canadian land rig count can be partially attributed to seasonality of activity in that market:







 Average Drilling Rig Count

Quarter Ended U.S. Land Canada Land North America Land





Over the past several years, North American E&P companies have been able to reduce their cost structures and have also utilized technologies, including ours, to increase efficiency and improve well performance. After a period of declining drilling and completion activity from late 2014 through early 2016, North American E&P companies began to increase activity levels beginning in the second quarter of 2016, as evidenced by increasing rig counts in the U.S. and Canada. The rate of increase slowed in the U.S. during 2018 and began to decline in 2019. The decline accelerated in 2020 before bottoming in the third quarter and increasing during the fourth quarter with the average U.S. rig count increasing by 23% in the fourth quarter of 2020 to 297 from a historically low level of 241 in the third quarter of 2020. The average land rig count in Canada for the fourth quarter was 36% lower than in the same period

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in 2019 and was at 58 rigs by the end of December 2020, up from 12 rigs at June 30, 2020, the lowest level ever recorded by Baker Hughes Company. The U.S. and Canadian rig counts are expected to remain significantly below prior year levels in 2021.



A substantial portion of our business is subject to quarterly variability. In Canada, we typically experience higher activity levels in the first quarter of each year, as our customers take advantage of the winter freeze to gain access to remote drilling and production areas. In the past, our revenue in Canada has declined during the second quarter due to warming weather conditions that result in thawing, softer ground, difficulty accessing drill sites and road bans that curtail drilling and completion activity. Access to well sites typically improves throughout the third and fourth quarters in Canada, leading to activity levels that are higher than in the second quarter, but lower than activity in the first quarter. Our business can also be impacted by a reduction in customer activity during the winter holidays in late December and early January. In recent years, many customers in the U.S. exhausted their capital budgets prior to the end of the year, leading to reductions in drilling and completion activity during the fourth quarter.



The market in Canada also continues to be impacted by logistical constraints in moving oil and natural gas from areas of production activity to demand centers. These constraints have led to lower realized pricing for our Canadian customers, which were partially offset by the initiatives implemented by the Province of Alberta. As a result, industry activity and capital spending in Canada in 2019 was materially below 2018 levels, both for producers of oil and liquids-rich natural gas and producers of natural gas. Commodity price differentials are forecasted to remain at elevated levels for an extended period of time, which we expect to continue to have a negative impact on customer activity.



The industry experienced a reduction in completions activity in the United States that began in the second half of 2018, which has extended through 2019 and into 2020, with the reduction further accelerating beginning in March 2020 before bottoming in the third quarter and increasing during the fourth quarter of 2020. In addition, initial capital budgets from E&P companies indicate that capital spending in 2021 is expected to be slightly below capital spending in 2020.



Adoption of Pinpoint Stimulation



Traditional well completion techniques, including plug and perf and ball drop, currently account for the majority of unconventional well completions in North America and over 90% of unconventional well completions in the U.S. We believe that pinpoint stimulation provides benefits compared to these traditional well completion techniques. Our ability to grow our market share, as evidenced by the percentage of horizontal wells in North America completed using our products and services, will depend in large part on the industry’s further adoption of pinpoint stimulation to complete wells, our ability to continue to innovate our technology to compete against continuing technological advances in competing traditional well completions techniques, and our ability to successfully compete with other providers of pinpoint stimulation products and services, including adjusting our pricing in certain markets to respond to customer demands and to competitors that may provide discounted pricing to our customers.



Increasing Well Complexity and Focus on Completion Optimization



In recent years, E&P companies have drilled longer horizontal wells and completed more hydraulic fracturing stages per well to maximize the volume of hydrocarbon recoveries per well. This trend towards longer and more complex wells has resulted in us selling more sliding sleeves or composite frac plugs per well on average, which increases our revenue opportunity per well completion and has led to increased sales of our AirLock casing buoyancy systems. Additionally, E&P companies have become increasingly focused on well productivity through optimization of completion designs and we believe this trend may further the adoption of pinpoint stimulation, and in turn, increase the opportunity for sales of our products and services if our customers observe operational benefits and long-term production results from the application of pinpoint stimulation. This trend towards more complex well completions has also resulted in increased use of tracer diagnostics services, which can be utilized to assess the effectiveness of various well completion techniques and well spacing strategies in support of completion and field development optimization efforts.



How We Generate Revenues



We derive our revenues from the sale of our fracturing systems products and the provision of related services, the sale of composite frac plugs and related products through Repeat Precision and from sales of our tracer diagnostics services, AirLock casing buoyancy system, liner hanger systems and toe initiation sleeves products.



Product sales represented 70%, 71% and 69% of our revenues for the years ended December 31, 2020, 2019 and 2018, respectively. Most of our sales are on a just-in-time basis, as specified in individual purchase orders, with a fixed price for our products. We occasionally supply our customers with large orders that may be filled on negotiated terms. Services represented 30%, 29% and 31% of our revenues for the years ended December 31, 2020, 2019 and 2018, respectively. Services include our tool charges and associated services related to our fracturing systems and tracer diagnostics services (which are classified together as “services” in our financial results). Services are provided at agreed upon rates to customers for the provision of our downhole frac isolation assembly, our personnel and for the provision of tracer diagnostics services.



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During periods of low drilling and well completion activity or as may be needed to compete in certain markets we will, in certain instances, lower the prices of our products and services. Our revenues are also impacted by well complexity, with wells with more stages resulting in longer jobs and increased revenue attributable to selling more sliding sleeves or composite frac plugs and the provision of our services.



For the years ended December 31, 2020, 2019 and 2018, approximately 45%, 42% and 48%, respectively, of our revenues were derived from sales in Canada and were denominated in Canadian dollars. Because our Canadian contracts are typically invoiced in Canadian dollars, the effects of foreign currency fluctuations impact our revenues and are regularly monitored.



Although most of our sales are to North American E&P companies, we also have sales to customers outside of North America and expect sales to international customers to increase over time. These international sales are made through local NCS entities or to our local operating partners on a free on board or free carrier basis with a point of sale in the United States. Some of the locations in which we have operating partners or sales representatives include China and the Middle East. Our operating partners and representatives do not have authority to contractually bind NCS but market our products in their respective territories as part of their product or service offering.



Costs of Conducting our Business



Our cost of sales is comprised of expenses relating to the manufacture of our products in addition to the costs of our support services. Manufacturing cost of sales includes payments made to our suppliers for raw materials and payments made to machine shops for the manufacturing of product components and finished assemblies and costs related to our employees that perform quality control analysis, assemble and test our products. Our strategic 50% purchase of Repeat Precision has allowed us to reduce our costs for certain product categories. We review forecasted activity levels in our business and either directly procure or ensure that our vendors procure the required raw materials with sufficient lead time to meet our business requirements. On March 8, 2018, the President of the United States signed an order to impose a tariff of 25% on steel imported from certain countries. On July 1, 2018, Canada implemented retaliatory tariffs on certain U.S. imports, including steel. These tariffs have continued to result in an increase in our cost of sales. On September 24, 2018, the United States implemented a tariff of 10% on a significant number of commodities originating from China, including certain chemicals utilized in our tracer diagnostics business. The tariffs were subsequently increased to 25% in May 2019. The increased tariffs have resulted in an increase in our cost of sales. While we strive to pass through some of the increases in raw material costs directly resulting from the tariffs to our customers, there can be no assurance that we will be able to do so. Cost of sales for support services includes compensation and benefit-related expenses for employees who provide direct revenue generating services to customers in addition to the costs incurred by these employees for travel and subsistence while on site. Cost of sales includes other variable manufacturing costs, such as shrinkage, obsolescence, revaluation and scrap related to our existing inventory and costs related to the chemicals and laboratory analysis associated with our tracer diagnostics services.



Our SG&A expenses are comprised of compensation expense, which includes compensation and benefit-related expenses for our employees who are not directly involved in revenue generating activities, including those involved in our research and development activities, as well as our general operating costs. These general operating costs include, but are not limited to: rent and occupancy for our facilities, information technology infrastructure services, software licensing, advertising and marketing, third party research and development, risk insurance and professional service fees for audit, legal and other consulting services. Our SG&A expenses also include severance expenses, litigation expenses and provisions for doubtful accounts. As a result of being a public company, our legal, accounting and other expenses have increased and may further increase for costs associated with our compliance with the Sarbanes-Oxley Act.



The percentage of our costs, defined as cost of sales, excluding depreciation and amortization, and including SG&A, denominated in Canadian dollars for the years ended December 31, 2020, 2019 and 2018, were approximately 19%, 22% and 21%, respectively.



How We Evaluate our Results of Operations



Our management uses a variety of financial and operating metrics to analyze our performance. These metrics are significant factors in assessing our results of operations and profitability and include:



Revenues



We primarily sell our products and services under purchase orders with pricing negotiated with individual customers. Our revenues are generated primarily from the sales of our fracturing systems, well construction and composite plug products and from services related to the utilization of our downhole frac isolation assembly as well as from the provision of tracer diagnostics and reservoir strategies services. We compare our actual revenue performance on a monthly, quarterly and annual basis to our annual budget, our most recent estimate for the relevant period, and to applicable market metrics.



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Adjusted EBITDA and Adjusted EBITDA Less Share-Based Compensation



EBITDA is defined as net (loss) income before interest expense, net, income tax (benefit) expense and depreciation and amortization. Adjusted EBITDA is defined as EBITDA adjusted to exclude certain items which we believe are not reflective of ongoing operating performance or which, in the case of impairments and share-based compensation, are non-cash in nature. Adjusted EBITDA Less Share-Based Compensation is calculated in the same manner as Adjusted EBITDA, with the sole exception being that it does not addback non-cash share-based compensation expense. We believe that Adjusted EBITDA is an important measure that excludes costs that management believes do not reflect our ongoing operating performance and certain costs associated with our capital structure. We believe that Adjusted EBITDA Less Share-Based Compensation presents our financial performance in a manner that is comparable to the presentation provided by many of our peers. Accordingly, Adjusted EBITDA and Adjusted EBITDA Less Share-Based Compensation are key metrics that management uses to assess the period-to-period performance of our core business operations. We believe that presenting Adjusted EBITDA and Adjusted EBITDA Less Share-Based Compensation enables investors to assess our performance from period to period using the same metrics utilized by management and also allows investors to evaluate our performance relative to other companies that are not subject to such factors. EBITDA, Adjusted EBITDA and Adjusted EBITDA Less Share-Based Compensation are not defined under GAAP, are not measures of net income, income from operations or any other performance measure derived in accordance with GAAP and are subject to important limitations. Adjusted EBITDA and Adjusted EBITDA Less Share-Based Compensation may not be comparable to similarly titled measures of other companies in our industry and are not measures of performance calculated in accordance with GAAP.



Free Cash Flow and Free Cash Flow Less Distributions to Non-Controlling Interest



We utilize free cash flow to evaluate the cash generated by our operations and results of operations. We define free cash flow as net cash provided by (used in) operating activities less purchases of property and equipment (inclusive of the purchase and development of software and technology) plus proceeds from sales of property and equipment, as presented in our consolidated statement of cash flows. Management believes free cash flow is useful because it provides information to investors regarding the cash that was available in the period that was in excess of our needs to fund our capital expenditures and other investment needs. We define free cash flow less distributions to non-controlling interest as free cash flow (as defined above) less distributions to non-controlling interest, as presented in the net cash used in financing activities section of our consolidated statements of cash flows. Management believes that free cash flow less distributions to non-controlling interest is useful because it provides information to investors regarding the cash that was available in the period that was in excess of our needs to fund our capital expenditures, other investment needs, and cash distributions to our joint venture partner, which have increased in recent years. Free cash flow and free cash flow less distributions to non-controlling interest do not represent our residual cash flow available for discretionary expenditures, as we have non-discretionary expenditures, including, but not limited to, repayment of outstanding balances under our Senior Secured Credit Facility, that are not deducted in calculating either free cash flow or free cash flow less distributions to non-controlling interest. Free cash flow and free cash flow less distributions to non-controlling interest are non-GAAP financial measures and should not be considered as an alternative to cash provided by operating activities as a cash flow measurement.

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Results of Operations



The following table summarizes our revenues and expenses for the years ended December 31, 2020 and 2019. A discussion of our results of operations for the year ended December 31, 2019 compared to the year ended December 31, 2018 is included in Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of our Annual Report on Form 10-K for the year ended December 31, 2019, filed with the SEC on March 3, 2020, and is incorporated by reference into this Form 10-K.









 Year Ended December 31, Variance

Revenues

Cost of sales

Change in fair value of contingent consideration — 37 (37) (100.0) %

Other income (expense)

Foreign currency exchange (loss) gain (1,060) (958) (102) (10.6) %

________________

(1) NM – Percentage not meaningful



Year Ended December 31, 2020 compared to Year Ended December 31, 2019



Revenues



Revenues were $107.0 million for the year ended December 31, 2020 as compared to $205.5 million for the year ended December 31, 2019. This decrease reflected reductions in product sales and services volumes in North America, particularly during the second, third and fourth quarters and lower product sales in international markets, partially offset by higher services revenue in international markets. We believe the decrease in both activity and pricing resulted from the decline in market conditions primarily related to the COVID-19 pandemic, which had a negative impact on our revenues during the year ended December 31, 2020 as drilling rig and completion activity in North America declined sequentially throughout 2020 before bottoming in the third quarter and increasing during the fourth quarter of 2020. In addition, customer activity in China was delayed and activity in Argentina was suspended from mid-March until June due to government regulations. Product sales for the year ended December 31, 2020 were $75.2 million as compared to $145.8 million for the year ended December 31, 2019. Our service revenue was $31.8 million for the year ended December 31, 2020 as compared to $59.7 million for the year ended December 31, 2019.



Cost of sales



Cost of sales was $62.9 million, or 58.8% of revenues, for the year ended December 31, 2020 as compared to $108.0 million, or 52.6% of revenues, for the year ended December 31, 2019. Cost of sales as a percentage of revenues increased due to the significant reduction in revenue, leading to under-utilization of manufacturing capacity and field service personnel, as well as a reduction in pricing for certain products and services, particularly during the second, third and fourth quarters. We believe that our cost of sales as

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a percentage of revenue was negatively impacted by the reduction in revenue activity associated with the decline in market conditions primarily related to the COVID-19 pandemic, which contributed to fixed cost under absorption. Cost of product sales was $46.6 million or 62.0% of product sales revenue and cost of services was $16.3 million or 51.2% of service revenue for the year ended December 31, 2020. For the year ended December 31, 2019, cost of product sales was $75.1 million or 51.5% of product sales revenue and cost of services was $32.9 million or 55.2% of service revenue.



Selling, general and administrative expenses



Selling, general and administrative expenses were $59.4 million for the year ended December 31, 2020 as compared to $88.6 million for the year ended December 31, 2019. This overall decrease in expense reflects declines in compensation and benefits, share-based compensation, bad debt, research and development and ERP-related expenses of $16.6 million, $4.1 million, $2.8 million, $1.6 million, and $1.3 million, respectively. We believe that travel restrictions enacted in response to the COVID-19 pandemic had a favorable impact on our SG&A expense, primarily due to a reduction in travel and entertainment expenses of $2.0 million. Additionally, professional fees, including litigation fees, were lower by $5.3 million. These favorable variances were partially offset by severance charges incurred for the year ended December 31, 2020 related to reductions in workforce, which was greater than 2019 by $4.9 million.



Depreciation



Depreciation was $4.4 million for the year ended December 31, 2020 as compared to $5.9 million for the year ended December 31, 2019. The decrease is primarily attributable to a non-cash impairment charge of $9.7 million during the first quarter of 2020, which reduced the carrying values of our land, building and improvements and machinery and equipment. Additionally, our capital expenditures were lower in 2020 compared to 2019. See “Note 6. Property and Equipment” of our consolidated financial statements for additional detail.



Amortization



Amortization was $1.5 million for the year ended December 31, 2020 as compared to $4.6 million for the year ended December 31, 2019. The decrease in amortization was related to non-cash impairment charges of $40.5 million during the first quarter of 2020, which reduced the carrying values of technology, internally-developed software, customer relationships, and trademarks. See “Note 7. Goodwill and Identifiable Intangibles” of our consolidated financial statements for additional detail.

Impairment



In the first quarter of 2020, we evaluated our property and equipment and finite-lived intangible assets for impairment due to current industry conditions such as a reduction in global economic growth expectations, a significantly reduced demand for crude oil and refined products, the significant decline in commodity prices and the corresponding impact on future expectations of demand for our products and services primarily related to the COVID-19 pandemic as well as the resulting decline in the quoted price of our common stock. We determined that the carrying amount of certain of our long-lived assets exceeded the corresponding fair value. We recorded impairment charges of $9.7 million in property and equipment and $40.5 million in finite-lived intangible assets.There were no impairment charges recorded on our goodwill, property and equipment or identifiable intangible assets during the remainder of 2020.



During the second quarter of 2019, we performed an impairment test for goodwill and determined that the carrying value of one of our reporting units exceeded its fair value. We recorded an impairment charge of $7.9 million for our tracer diagnostic services reporting unit as a result of a further deterioration in customer activity levels in North America. This resulted in lower demand for oilfield services driving a decrease in our business volumes and increased customer and competitor-driven pricing pressures in addition to a decline in the quoted price of our common stock. In addition to goodwill, we also assessed our identifiable intangibles for impairment during the second quarter of 2019 and determined those assets were not impaired. There were no additional indications of impairment during the remainder of 2019.



See “Note 2. Summary of Significant Accounting Policies” and “Note 7. Goodwill and Identifiable Intangibles” of our consolidated financial statements for additional detail related to these charges.



Gain on patent infringement settlement



Gain on patent infringement settlement was $25.7 million for the year ended December 31, 2020, which represents the gain realized fromthe settlement of the final court judgment against Diamondback and includes $1.1 million of proceeds from our directors and officers liability insurance related to the reimbursement of legal expenses that we incurred to defend a director and officer in the Diamondback litigationand is net of related legal fees incurred in 2020 of $2.7 million. See “Note 10.Commitments and Contingencies” of our consolidated financial statements.

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Other income, net



Other income, net was $1.7 million for the year ended December 31, 2020 compared to $0.3 million for the year ended December 31, 2019. The increase was primarily due to gain on sales of fixed assets and income recognized as a result of our technical services and assistance agreement with Special Oilfield Services Co. LLC. See “Note 10.Commitments and Contingencies” of our consolidated financial statements.



Income tax (benefit) expense



Income tax (benefit) expense was $(7.8) million for the year ended December 31, 2020 as compared to $10.8 million for the year ended December 31, 2019.Included in the tax benefit for the year ended December 31, 2020 were several U.S. tax (benefit) expense adjustments related to the enactment of the Coronavirus Aid, Relief, and Economic Security Act (the “CARES Act”) including a tax benefit of $(0.9) million related to a Net Operating Loss (“NOL”) carryback allowed under the CARES Act that was previously unavailable, and atax expense of $6.5 million for an increase in a valuation allowance on deferred tax assets not expected to be realized. Also included in tax benefit for the year ended December 31, 2020 was a tax expense of $1.4 million for a valuation allowance against our Canadian deferred tax asset based on management’s position that NCS has not met the more likely than not condition of realizing part of the deferred tax asset, as well as a benefit of $(1.5) million related to non-U.S. income taxed at different rates. Included in tax expense for the year ended December 31, 2019 was a valuation allowance against our U.S. deferred tax asset as well as the tax effect of a non-deductible goodwill impairment. These adjustments resulted in additional tax expense for the year ended December 31, 2019 of approximately $13.1 million. Additionally, the tax (benefit)expense for the years ended December 31, 2020 and 2019 included a tax expense of $1.0 million and $0.9 million, respectively, for the tax effect of stock awards.



On March 27, 2020, the CARES Act was enacted and signed into law and includes several provisions for corporations including allowing companies to carryback certain NOLs and increasing the amount of NOLs that corporations can use to offset income. Corporate taxpayers may carryback NOLs originating during 2018 through 2020 for up to five years. In addition, the CARES Act removes the 80% taxable income limitation on utilization of those NOLs if carried back to prior tax years or utilized in tax years beginning before 2021.



As a result of the geographic mix of earnings and losses, including discrete items, our tax rate has been and will continue to be volatile.



Liquidity and Capital Resources



Our primary sources of liquidity are our existing cash and cash equivalents, cash provided by operating activities and borrowings under our Senior Secured Credit Facility. As of December 31, 2020, we had cash and cash equivalents of $15.5 million, and total outstanding indebtedness of $5.8 million, of which no amount is currently outstanding under our Senior Secured Credit Facility. The Senior Secured Credit Facility consists of a senior secured revolving credit facility in an aggregate principal amount of $25.0 million. Total borrowings are limited to a borrowing base calculated based on eligible receivables, provided that it does not include receivables at Repeat Precision.We were in compliance with our debt covenants at December 31, 2020. We believe that our cash on hand, cash flows from operations and potential borrowings under our Senior Secured Credit Facility will be sufficient to fund our capital expenditure and liquidity requirements for the next twelve months. Our borrowing base under the Senior Secured Credit Facility at December 31, 2020 was $11.0 million. The amount available to be drawn under the Senior Secured Credit Facility may decline from current levels due to reductions in our borrowing base or a springing financial covenant if our business continues to be adversely impacted by a decline in market conditions primarily related to the COVID-19 pandemic. Our principal liquidity needs have been, and are expected to continue to be, capital expenditures, working capital, severance payments, debt service and potential mergers and acquisitions.



We plan to incur approximately $1 million to $2 million in capital expenditures during 2021, which includes (i) additional machining and other capital equipment at Repeat Precision, (ii) internally-developed software, (iii) additional equipment to support our tracer diagnostics services and (iv) vehicles used in international operations. Our capital expenditures, including the purchase and development of software and technology, for the years ended December 31, 2020, 2019 and 2018 were $2.2 million, $6.4 million and $15.8 million, respectively. Our 2020 capital expenditures included (i) additional machining capacity at Repeat Precision, (ii) machinery and equipment utilized in manufacturing and engineering, (iii) additional equipment to support our tracer diagnostics services and (iv) leasehold improvements associated with operations facilities. We generated proceeds from the sale of property and equipment of $1.1 millionfor the year ended December 31, 2020, primarily related to the sale of excess vehicles utilized in field operations, most of which were obtained through finance leases.



We anticipate that to the extent we require additional liquidity to fund our capital requirements or repay existing indebtedness, it will be funded through the incurrence of additional indebtedness, the proceeds of equity issuances, or a combination thereof. We cannot assure you that we will be able to obtain this additional liquidity on reasonable terms, or at all. Our liquidity and our ability to

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meet our obligations and fund our capital requirements are also dependent on our future financial performance and ability to reduce costs, which is subject to general economic, financial and other factors that are beyond our control, including the COVID-19 pandemic. Accordingly, we cannot assure you that our business will generate sufficient cash flow from operations or that funds will be available from additional indebtedness, the capital markets or otherwise to meet our liquidity needs. If we decide to pursue one or more significant acquisitions, we may incur additional debt or sell additional equity to finance such acquisitions, which could result in additional expenses or dilution.



Cash Flows, Free Cash Flow and Free Cash Flow Less Distributions to Non-Controlling Interest



The following table provides a summary of cash flows from operating, investing and financing activities for the periods presented (in thousands):







 Year Ended December 31,

Effect of exchange rate changes on cash and cash equivalents 17 471 (2,164)

Net change in cash and cash equivalents $ 4,302 $ (13,888) $ (8,678)

_______________



Free Cash Flow:







 Year Ended December 31,

Purchase and development of software and technology (55) (251) (4,675)

Proceeds from sales of property and equipment 1,094 1,372 399



Free Cash Flow Less Distributions to Non-Controlling Interest:







 Year Ended December 31,

Purchase and development of software and technology (55) (251) (4,675)

Proceeds from sales of property and equipment 1,094 1,372 399



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Operating Activities



Net cash provided by operating activities was $35.1 million compared to $17.9 million for the years ended December 31, 2020 and 2019, respectively. The increase in cash flow in 2020 reflects receipt of $21.4 million in cash at Repeat Precision associated with a patent infringement settlement, no payment of contingent consideration in 2020 as compared to $3.0 million in 2019 and favorable changes in accounts receivable and inventories balances. These items were partially offset by lower net income in 2020 as compared to 2019, primarily due to an overall decrease in activity levels resulting largely from the COVID-19 pandemic and unfavorable changes in deferred income tax (benefit) expense, prepaid expenses and other assets, accounts payable and income taxes receivable/payable as well as lower share-based compensation and depreciation and amortization expenses.



Net cash provided by operating activities was $17.9 million and $14.0 million for the years ended December 31, 2019 and 2018, respectively. The increase in cash flow was primarily driven by higher net income in 2019 compared to 2018 with favorable changes in accounts receivable, accounts payable, deferred tax (expense) benefit and income tax receivable/payable partially offset by the unfavorable changes in inventories and the payment of contingent consideration.



Investing Activities



Net cash used in investing activities was $1.1 million and $5.0 million for the years ended December 31, 2020 and 2019, respectively. The decrease in cash used in investing activities during the year ended December 31, 2020 as compared to the year ended December 31, 2019 was primarily related to reduced capital expenditures for property, equipment, software and technology which totaled $2.2 million for the year ended December 31, 2020 compared to $6.4 million for the same period in 2019.



Net cash used in investing activities was $5.0 million and $15.4 million for the years ended December 31, 2019 and 2018, respectively. The decrease in cash used in investing activities during the year ended December 31, 2019 as compared to the year ended December 31, 2018 was primarily related to capital expenditures, including property, equipment, software and technology, of $6.4 million for the year ended December 31, 2019 compared to $15.8 million for the same period in 2018.



Financing Activities



Net cash used in financing activities for the years ended December 31, 2020 and 2019 was $29.8 million and $27.3 million, respectively. The increase was primarily related to distributions to our joint venture partner of $17.6 million during the year ended December 31, 2020 as compared to $6.0 million of distributions for the same period in 2019. The increase was partially offset by lower payments on equipment note and finance leases of $3.5 million. Additionally, on January 31, 2019, we made a $10.0 million cash payment to the joint venture partner for the Repeat Precision earn-out consideration, of which $7.0 million was classified as a financing activity to reflect the acquisition date fair value of the contingent consideration liability and $3.0 million was included in operating activities as the liability was settled at an amount greater than the acquisition date fair value.



The net cash used in financing activities for the years ended December 31, 2019 and 2018 was $27.3 million and $5.1 million, respectively. The increase was primarily related to the $10.0 million cash payment to the joint venture partner for the Repeat Precision earn-out consideration on January 31, 2019, of which $7.0 million was classified as a financing activity to reflect the acquisition date fair value of the contingent consideration liability and $3.0 million was included in operating activities as the liability was settled at an amount greater than the acquisition date fair value. We also made cash payments totaling $10.0 million on our Senior Secured Credit Facility (as defined below) during the second, third, and fourth quarters of 2019 and made distributions to our joint venture partner of $6.0 million during the year ended December 31, 2019 as compared to $2.3 million of distributions for the same period in 2018.



Financing Arrangements



On May 1, 2019, we entered into a Second Amended and Restated Credit Agreement (the “2019 Credit Agreement”) with Pioneer Investment, Inc., as U.S. borrower (the “U.S. Borrower”), NCS Multistage Inc., as Canadian borrower (the “Canadian Borrower”; together with the U.S. Borrower, the “Borrowers”), Pioneer Intermediate, Inc. (together with the Company, the “Parent Guarantors”), the lenders party thereto, Wells Fargo Bank, National Association as administrative agent (the “U.S. Agent”) in respect of the U.S. facility provided therein and Wells Fargo Bank, National Association, Canadian Branch, as administrative agent (the “Canadian Agent”) in respect of the Canadian Facility provided therein. The 2019 Credit Agreement amended and restated our prior credit agreement in its entirety. See “Note 9. Debt” to our consolidated financial statements for additional details regarding our 2019 Credit Agreement.



On August 6, 2020, we entered into Amendment No. 1 to Second Amended and Restated Credit Agreement (the “Amendment”; the 2019 Credit Agreement, as amended by the Amendment, the “Amended Credit Agreement”) with the Borrowers, Pioneer Intermediate, Inc., certain subsidiaries of the Borrowers, the lenders party thereto, the U.S. Agent and the Canadian Agent. The facility provided pursuant to the Amended Credit Agreement is referred to herein as the “Senior Secured Credit Facility”.



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The Senior Secured Credit Facility consists of a senior secured revolving credit facility in an aggregate principal amount of $25.0 million made available to the U.S. Borrower, of which up to $2.5 million may be made available for letters of credit and up to $2.5 million may be made available for swingline loans. The Canadian Borrower may make borrowings under the Senior Secured Credit Facility, subject to a $15.0 million sublimit. Total borrowings available to the Borrowers under the Senior Secured Credit Facility is limited to a borrowing base calculated based on eligible receivables, provided that it does not include receivables at Repeat Precision. The Senior Secured Credit Facility will mature on May 1, 2023.



Borrowings under the Senior Secured Credit Facility may be made in USD for Adjusted Base Rate Advances, and in USD, Canadian dollars or Euros for Eurocurrency Rate Advances (each as defined in the Amended Credit Agreement). Such advances bear interest at the Adjusted Base Rate or at the Eurocurrency Rate (each as defined in the Amended Credit Agreement) plus an applicable interest margin between 2.75% and 3.75%, depending on NCS’s leverage ratio.



The obligations of the Borrowers under the Senior Secured Credit Facility are guaranteed by the Parent Guarantors, as well as each of the other existing and future direct and indirect restricted subsidiaries of NCS organized under the laws of the United States and Canada (subject to certain exceptions), and are secured by substantially all of the assets of the Parent Guarantors, the Borrowers and such other subsidiary guarantors, in each case, subject to certain exceptions and permitted liens.



The Amended Credit Agreement requires us to (i) maintain liquidity (defined as availability under the Senior Secured Credit Facility plus certain cash deposits) of at least $7.5 million as of the date of each borrowing base certificate due to be delivered either monthly (if availability is greater than or equal to than 12%) or weekly (if availability is less than 12%) thereunder, (ii) maintain, for quarters during which availability is less than 20% of the borrowing base, a fixed charge coverage ratio of at least 1.0 to 1.0 and (iii) on the last business day of each week, prepay advances to the extent that available cash exceeds $12.0 million. As of December 31, 2020, we were in compliance with these financial covenants. The Amended Credit Agreement also contains customary affirmative and negative covenants, including, among other things, restrictions on the creation of liens, the incurrence of indebtedness, investments, dividends and other restricted payments, dispositions and transactions with affiliates.



The Amended Credit Agreement includes customary events of default for facilities of this type (with customary materiality thresholds and grace periods, as applicable). If an event of default occurs, the lenders party to the Amended Credit Agreement may elect (after the expiration of any applicable notice or grace periods) to declare all outstanding borrowings under such facility, together with accrued and unpaid interest and other amounts payable thereunder, to be immediately due and payable. The lenders party to the Amended Credit Agreement also have the right upon an event of default thereunder to terminate any commitments they have to provide further borrowings and to proceed against the collateral securing the Senior Secured Credit Facility.



Repeat Precision also has outstanding promissory notes with an aggregate borrowing capacity of up to $9.3 million, subject to a borrowing base. See “Note 9. Debt” of our consolidated financial statements for further information regarding the promissory notes.



Contractual Obligations



The following table presents our contractual obligations and other commitments as of December 31, 2020 (in thousands):







 Total Less than1 year 1-3 years 3- 5 years More than5 years



_______________



Off-Balance Sheet Arrangements



We have no off-balance sheet financing arrangements.



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Effects of Inflation



We do not believe that the effects of inflation have had a material effect on our business, financial condition or results of operations. However, if our costs become subject to significant inflationary pressures, we may not be able to offset such increased costs through price increases. Our inability or failure to offset any such cost increases in the future could have a material adverse effect on our business, financial condition and results of operations.



Critical Accounting Policies



Our discussion and analysis of our financial condition and results of operations is based upon our consolidated financial statements, which have been prepared in accordance with GAAP. The preparation of these consolidated financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenue and expenses. Certain of our accounting policies require the application of significant judgment by management in selecting the appropriate assumptions for calculating financial estimates. By their nature, these judgments are subject to an inherent degree of uncertainty. Our actual results may differ from these estimates. The accounting policies that we believe to be the most critical to an understanding of our financial condition and results of operations and that require the most complex and subjective management judgments are discussed below.



Revenue Recognition



We derive our revenues primarily from highly engineered products and support services. Revenues are based upon a purchase order, contract or other persuasive evidence of an arrangement with the customer that includes a fixed or determinable price, provided that collectability is reasonably assured, but such arrangements do not generally include right of return or other similar provisions or other significant post-delivery obligations. Sales and value added taxes that we collect concurrent with revenue-producing activities are excluded from revenue. We recognize revenue through the following steps: (i) identify the contract, (ii) identify the performance obligations, (iii) determine the transaction price, (iv) allocate the transaction price and (v) satisfy the performance obligation. For the year ended December 31, 2020, we recognized revenue from our largest customer totaling $10.2 million, or 10% of total revenue for the year. Amounts due from this customer included in our trade accounts receivable balance was $2.6 million, or 12% of our trade accounts receivable balance as of December 31, 2020. No other customer individually accounted for 10% or more of our consolidated revenue during 2020. No single customer individually accounted for 10% or more of our consolidated revenue during the years ended 2019 and 2018. One customer accounted for 10% of our trade accounts receivable balance as of December 31, 2019 while another customer accounted for 12% of our trade accounts receivable balance as of December 31, 2018.



On occasion, we issue credits to our customers that are related specifically to the performance of our products or the services we provide, with such credits reducing the amount of revenue for the completed sales. These credits are infrequent, situation specific and cannot be individually estimated in advance.



The payment terms and conditions in our customer contracts vary. We do not have contracts that contain a financing component and do not accept noncash consideration from customers.



NCS has elected to recognize shipping and handling costs when control of the product transfers to the customer. These costs are included in cost of sales in our consolidated statements of operations.



Product Sales Revenues



For product sale arrangements that are standard inventory products or modified inventory products with an alternative use, revenue is recognized at a point in time when control transfers. Control generally transfers upon shipment or delivery, and delivery is based on the customer instructions. Customers may also request bill and hold arrangements in writing. Once we have completed the bill and hold order, the products are segregated from the rest of inventory in the warehouse. The transaction price for product sales having a performance obligation is the price per unit times the unit quantity ordered and shipped to the customer or consumed at the well site.



Services Revenues



For service arrangements that do not have a contract provision with a right to a payment for services up to the date of termination, revenue is recognized when the job has been completed, which usually includes a customer signature or acknowledgement and when there are no additional services or future obligations required by us. The transaction price is determined by the contract unit day rate times the cumulative number of days of service provided upon the completion of the service and upon customer acceptance or a contract rate for materials provided in connection with the service.



For service arrangements that do have a contract provision with a right to payment for services up to the date of termination, revenue is recognized over time using a unit rate (labor and materials) output method that corresponds to the value we would receive

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upon termination of the contract at a reporting period. In applying the output method at the end of a quarter, we check that there is no material work in progress that is not in the measurement of the output. The transaction price for the period end is determined by the contract unit rate times the cumulative number of units earned up to the reporting period less any revenue recognized in prior periods.



Allowance for Doubtful Accounts



We maintain an allowance for doubtful accounts for estimated losses that may result from the inability of our customers to make required payments. Earnings are charged with a provision for doubtful accounts based on a current review of the collectability of customer accounts by management. Such allowances are based upon several factors including, but not limited to, credit approval practices, industry and customer historical experience as well as the current and projected financial condition of the specific customer. Accounts deemed uncollectible are applied against the allowance for doubtful accounts. We have recorded $0.6 million and $0.5 million in our allowance for doubtful accounts as of December 31, 2020 and 2019, respectively.



Inventories



Inventories consist primarily of raw material, product components, assembled products, certain components used to internally construct our frac isolation assemblies, and chemicals used in our tracer diagnostics services in raw materials or finished goods. Inventories are stated at the lower of cost or estimated net realizable value. Cost is determined at standard costs approximating the first-in, first-out or average cost basis. We continuously evaluate inventories, based on an analysis of inventory levels, historical sales experience and future sales forecasts, to determine obsolete, slow-moving and excess inventory. Adjustments to reduce such inventory to its estimated recoverable value have been recorded as an adjustment to cost of sales.



Impairments



We evaluate our property and equipment and finite-lived intangible assets for impairment whenever changes in circumstances indicate that the carrying amount of an asset group may not be recoverable. Should the review indicate that the carrying value is not fully recoverable, the amount of the impairment loss is determined by comparing the carrying value to the estimated fair value. We assess recoverability based on undiscounted future net cash flows. Estimating future net cash flows requires us to make judgments regarding long-term forecasts of future revenues and costs related to the assets subject to review. These forecasts are uncertain in that they require assumptions about our revenue growth, operating margins, capital expenditures, future market conditions and technological developments. If changes in these assumptions occur, our expectations regarding future net cash flows may change such that a material impairment could result. For the year ended December 31, 2020, we recognized an impairment charge of $50.2 million related to property and equipment and identified intangible assets. There was no impairment of property and equipment and finite-lived intangible assets during the year ended December 31, 2019. For the year ended December 31, 2018, we recognizedan impairment charge of $73.5 million related to identifiable intangible assets. There was no impairment related to property and equipment in 2018. See “Note 2. Summary of Significant Accounting Policies”, “Note 6. Property and Equipment” and “Note 7. Goodwill and Identifiable Intangibles” of our consolidated financial statements for further information related to these charges.



An assessment of potential goodwill impairment indicators is performed annually or when there is an indication an impairment may have occurred. We typically complete our annual impairment test for goodwill using an assessment date in the fourth quarter of each fiscal year. Under generally accepted accounting principles, we have the option to first assess qualitative factors to determine whether the existence of events or circumstances leads to a determination that it is more likely than not that the fair value of one or more of our reporting units is greater than its carrying amount. If, after assessing the totality of events or circumstances, we determine it is more likely than not that the fair value of a reporting unit is greater than its carrying amount, there is no need to perform any further testing. However, if we conclude otherwise, then we are required to perform a quantitative impairment test by calculating the fair value of the reporting unit and comparing this value with the carrying value of the reporting unit. We also have the option to bypass the qualitative assessment for any reporting unit in any period and proceed directly to performing the quantitative goodwill impairment test. The fair value of the reporting unit is determined using a combination of a market multiple and a discounted cash flow approach. Determining the fair value of a reporting unit requires the use of estimates, assumptions and judgment. The principal estimates and assumptions that we use include revenue growth, operating margins, capital expenditures, future market conditions, weighted average costs of capital, a terminal growth rate, the set of comparable companies utilized, and the earnings metrics and multiples utilized. We believe that the estimates and assumptions used in impairment assessments are reasonable. If the fair value of the reporting unit is less than the carrying amount, an impairment charge is recorded in the amount of the difference. No impairment charge was recorded for the year ended December 31, 2020. For the year ended December 31, 2019, we recognized an impairment charge of $7.9 million for our tracer diagnostic services reporting unit. For the year ended December 31, 2018, we recognized an impairment charge of $154.0 million for two reporting units, fracturing systems and well construction of $122.1 million and tracer diagnostic services of $31.9 million. See “Note 7. Goodwill and Identifiable Intangibles” for further information related to these charges.



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Property and Equipment



Property and equipment are stated at historical cost adjusted for impairment, less accumulated depreciation. Equipment held under finance leases are stated at the present value of minimum lease payments at inception of the lease, less accumulated depreciation. Expenditures for property and equipment and for items which substantially increase the useful lives of existing assets are capitalized at cost and depreciated over their estimated useful life utilizing the straight-line method. Routine expenditures for repairs and maintenance are expensed as incurred. Depreciation is calculated over the estimated useful lives of the related assets using the straight-line method. Leasehold improvements and property under finance leases are amortized over the shorter of the remaining lease term or useful life of the related asset. Depreciation expense includes amortization of assets under finance leases. The cost and related accumulated depreciation of assets retired or otherwise disposed of are eliminated from the accounts, and any resulting gains or losses are recognized in the year of disposal as a component of other income, net.



Depreciation on property and equipment, including assets held under finance leases, is calculated using the straight-line method over the following useful service lives or lease term (which includes reasonably assured renewal periods):









 Years

Buildings 30

Building equipment and leasehold improvements 1 - 15

Machinery and equipment and service equipment 5 - 12

Computers and software 3 - 5

Furniture and fixtures 3 - 5

Vehicles 2 - 4

Right of use assets - finance leases Lease term (3-10)



Business Combinations, Goodwill and Intangible Assets



Business combinations are accounted for under the acquisition method of accounting in accordance with Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 805, Business Combinations. Under the acquisition method of accounting, the total consideration transferred in connection with the acquisition is allocated to the tangible and intangible assets acquired, liabilities assumed, and any non-controlling interest in the acquiree based on their fair values. Goodwill acquired in connection with business combinations represents the excess of consideration transferred over the net tangible and identifiable intangible assets acquired. Certain assumptions and estimates are employed in evaluating the fair value of assets acquired and liabilities assumed. These estimates may be affected by factors such as changing market conditions, technological advances in the oil and natural gas industry or changes in regulations governing that industry. The most significant assumptions requiring judgment involve identifying and estimating the fair value of intangible assets and the associated useful lives for establishing amortization periods. To finalize purchase accounting for significant acquisitions, we utilize the services of independent valuation specialists to assist in the determination of the fair value of acquired intangible assets.



Costs related to the acquisition, other than those associated with the issuance of debt or equity securities, that we incur in connection with a business combination are expensed as incurred.



Any contingent consideration payable is recognized at fair value at the acquisition date. Liability-classified contingent consideration is remeasured each reporting period with changes in fair value recognized in earnings until the contingent consideration is settled.



All identifiable intangibles are amortized on a straight-line basis over the estimated useful life or term of related agreements. Deferred loan costs are amortized to interest expense using the effective interest method. Certain costs incurred in the development of internal-use software applications are capitalized and costs incurred outside of the software application development stage are expensed as incurred. The amounts capitalized are included in intangible assets, categorized as internally developed software, and are amortized on a straight-line basis over the estimated useful life of the software when ready for the intended use. These assets are tested for impairment whenever events or changes in circumstances indicate that their carrying amount may not be recoverable.



Income Taxes



We are taxed as a corporation as defined under the Internal Revenue Code. The liability method is used in accounting for deferred income taxes. Under this method, deferred tax assets and liabilities are determined based on the difference between the financial reporting and tax bases of assets and liabilities and are measured using the enacted tax rates and laws that will be in effect when these differences are expected to reverse. The realizability of deferred tax assets is evaluated annually and a valuation allowance is provided if it is more likely than not that the deferred tax assets will not give rise to future benefits. We recognize tax benefits from uncertain tax positions only if it is more likely than not that the tax position will be sustained, based upon technical merits, upon examination by the taxing authorities. If the income tax position is expected to meet the more likely than not criteria, the benefit

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recorded in the consolidated financial statements equals the largest amount that is greater than 50% likely to be realized upon its ultimate settlement. A valuation allowance to reduce deferred tax assets is established when it is more likely than not that some portion or all the deferred tax assets will not be realized.



Share-Based Compensation



We account for our stock-based compensation awards in accordance with ASC Topic 718, Compensation— Stock Compensation (“ASC 718”). We recognize compensation cost for all share-based payment transactions, including compensation cost associated with the grant of options, equity-classified restricted stock units (“RSUs”), equivalent stock units, or cash-settled, liability-classified RSUs (“ESUs”), and performance stock unit awards (“PSUs”). To determine the compensation cost we use the Black-Scholes model for options, Monte Carlo simulation for the PSUs, and the market price of the common stock on the date of the grant for the RSUs and ESUs. As the ESUs will be settled in cash, the compensation cost is remeasured each reporting period at fair value based upon the closing stock price of our common stock until the awards are settled. Expense is recognized ratably from one to five years based upon the requisite service period.



We also have an ESPP, which allows eligible employees to purchase shares of our common stock. The purchase price of the stock is 85% of the lower of the stock price at the beginning or end of the offering period. The fair value of the employees’ purchase rights under the ESPP is estimated using the Black-Scholes model. The ESPP was temporarily suspended for future offering periods beginning on July 1, 2019. For additional information, see “Note 13. Share-Based Compensation” of our consolidated financial statements.



Severance and Other Termination Benefits



We accrue one-time severance costs pursuant to an approved workforce reduction plan at the communication date, when affected employees have been notified of the potential severance and sufficient information has been provided for the employees to calculate severance benefits, in the event the employee is involuntarily terminated. During 2020, we recorded $5.7 million of severance expense associated with one-time severance cost, of which a liability of $0.7 million remained at December 31, 2020.



Recently Issued Accounting Pronouncements



See “Note 2. Summary of Significant Accounting Policies” to our consolidated financial statements for discussion of the accounting pronouncements we recently adopted and the accounting pronouncements recently issued by the FASB.



Emerging Growth Company and Smaller Reporting Company Status



We are an “emerging growth company” as defined in the Jumpstart Our Business Startups Act of 2012 (the “JOBS Act”). We will remain an emerging growth company until the earlier of (1) the last day of our fiscal year (a) following the fifth anniversary of the completion of our IPO, (b) in which we have total annual gross revenue of at least $1.07 billion, or (c) in which we are deemed to be a large accelerated filer, which means the market value of our common stock that is held by non-affiliates exceeds $700.0 million as of the last business day of our most recently completed second fiscal quarter, and (2) the date on which we have issued more than $1.0 billion in non-convertible debt securities during the prior three-year period. Additionally, we are also a “smaller reporting company” as defined by Section 12b-2 of the Exchange Act, meaning that we are not an investment company, an asset-backed issuer, or a majority-owned subsidiary of a parent company that is not a smaller reporting company and have a public float of less than $250 million. As an emerging growth company and a smaller reporting company, we may take advantage of specified reduced reporting and other burdens that are otherwise applicable generally to public companies that do not qualify for those classifications.



Item 7A. Quantitative and Qualitative Disclosures About Market Risk



Our financial position is exposed to a variety of risks, including commodity price risk, foreign currency exchange rate risk, interest rate risk and credit risk. We have seen an increase in these risks and related uncertainties with increased volatility in oil and gas prices and the financial markets as a result of the COVID-19 pandemic.



Commodity Price Risk



The market for our products and services is indirectly exposed to fluctuations in the prices of crude oil and natural gas to the extent such fluctuations impact drilling and completion activity levels and thus impact the activity levels of our customers in the E&P industry. Additionally, because we do not sell our products under long-term contracts, we believe we are particularly exposed to short-term fluctuations in the prices of crude oil and natural gas. We do not currently intend to hedge our indirect exposure to commodity price risk.



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Foreign Currency Exchange Rate Risk



A substantial amount of our revenues is derived in Canada and, accordingly, our competitiveness and financial results are subject to foreign currency fluctuations where revenues and costs are denominated in Canadian dollars rather than USD. During the years ended December 31, 2020, 2019 and 2018, approximately 45%, 42% and 48%, respectively, of our revenues were attributable to our operations in Canada. We may use foreign currency forward exchange contracts to hedge our future exposure to the Canadian dollar. We also derive revenue from several jurisdictions outside of North America, including countries that occasionally experience periods of significant inflation, which occurred in Argentina in 2019 and 2020. We do not currently intend to hedge our future exposure to the Argentine Peso or other foreign currencies.



Interest Rate Risk



We are primarily exposed to interest rate risk through our Senior Secured Credit Facility, which was amended on August 6, 2020. The Amended Credit Agreement has similar terms and conditions, is subject to variable interest rates and consists of a U.S. Facility. As of December 31, 2020, we had no outstanding indebtedness under our Senior Secured Credit Facility.



Borrowings under the Senior Secured Credit Facility may be made in USD for Adjusted Base Rate Advances, and in USD, Canadian dollars or Euros for Eurocurrency Rate Advances (each as defined in the Amended Credit Agreement). Such advances bear interest at the Adjusted Base Rate or at the Eurocurrency Rate (each as defined in the Amended Credit Agreement) plus an applicable interest margin between 2.75% and 3.75%, depending on NCS’s leverage ratio. The applicable interest rate at December 31, 2020 was 4.375%.



Credit Risk



Our customers are E&P companies and other oilfield services companies. This concentration of counterparties operating in a single industry may increase our overall exposure to credit risk, in that the counterparties may be similarly affected by changes in economic, regulatory or other conditions. We manage credit risk by analyzing the counterparties’ financial condition prior to accepting new customers and prior to adjusting existing credit limits.

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Item 8. Financial Statements and Supplementary Data



INDEX TO FINANCIAL STATEMENTS





 Page

CONSOLIDATED FINANCIAL STATEMENTS

Report of Independent Registered Public Accounting Firm 61

Consolidated Balance Sheets as of December 31, 2020 and 2019 62

Notes to Consolidated Financial Statements 67



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Report of Independent Registered Public Accounting Firm



To the Board of Directors and Stockholders of NCS Multistage Holdings, Inc.

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of NCS Multistage Holdings, Inc. and its subsidiaries (the “Company”) as of December 31, 2020 and 2019, and the related consolidated statements of operations, of comprehensive loss, of changes in stockholders’ equity and of cash flows for each of the three years in the period ended December 31, 2020, including the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2020 and 2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2020 in conformity with accounting principles generally accepted in the United States of America.



Change in Accounting Principle

As discussed in Note 15 to the consolidated financial statements, the Company has changed its method for accounting for leases in 2019 due to the adoption of ASU No. 2016-02, Leases (Topic 842).

Basis for Opinion

These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits of these consolidated financial statements in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ PricewaterhouseCoopers LLP

Houston, Texas

March 8, 2021

We have served as the Company’s auditor since 2013, which includes periods before the Company became subject to SEC reporting requirements.



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NCS MULTISTAGE HOLDINGS, INC.

CONSOLIDATED BALANCE SHEETS

(In thousands, except share data)









 December 31, December 31,

Assets

Current assets

Prepaid expenses and other current assets 2,975 2,444

Noncurrent assets

Deferred income taxes, net 205 6

Liabilities and Stockholders’ Equity

Current liabilities

Current maturities of long-term debt 1,347 1,481

Noncurrent liabilities

Long-term debt, less current maturities 4,442 11,436

Operating lease liabilities, long-term 3,989 3,487

Deferred income taxes, net 13 2,956

Commitments and contingencies (Note 10)

Stockholders’ equity

Accumulated other comprehensive loss (81,780) (80,811)

Treasury stock, at cost; 12,074 shares at December 31, 2020 and 4,633 shares

Total liabilities and stockholders' equity $ 138,678 $ 202,577

_______________



The accompanying notes are an integral part of these consolidated financial statements.

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NCS MULTISTAGE HOLDINGS, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per share data)





 Year Ended December 31,

Revenues

Cost of sales

Change in fair value of contingent consideration — 37 (2,872)

Other income (expense)

Gain on patent infringement settlement 25,678 — —

Foreign currency exchange (loss) gain (1,060) (958) 162

Net income attributable to non-controlling interest 18,493 10,005 5,086

Loss per common share

Weighted average common shares outstanding

________________





The accompanying notes are an integral part of these consolidated financial statements.

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NCS MULTISTAGE HOLDINGS, INC.

CONSOLIDATED STATEMENTS OF COMPREHENSIVELOSS

(In thousands)





 Year Ended December 31,

Foreign currency translation adjustments, net of tax of $0 (969) 3,219 (17,323)



The accompanying notes are an integral part of these consolidated financial statements.

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NCS MULTISTAGE HOLDINGS, INC.

CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY

(In thousands, except share data)





Share- based compensation — — — — 10,930 — — — — — 10,930

Distribution to non-controlling interest — — — — — — — — — (2,300) (2,300)

Vesting of restricted stock — — 1,836 — — — — — — — —

Shares withheld — — — — — — — (498) (162) — (162)

Cemblend exchangeable shares — — 22,115 — — — — — — — —

Currency translation adjustment — — — — — (17,323) — — — — (17,323)

Share-based compensation — — — — 12,204 — — — — — 12,204

Distribution to noncontrolling interest — — — — — — — — — (6,000) (6,000)

Vesting of restricted stock — — 10,320 — — — — — — — —

Shares withheld — — — — — — — (3,218) (315) — (315)

Cemblend exchangeable shares (1) — 66,347 1 (1) — — — — — —

Proceeds from the issuance of ESPP shares — — 13,584 — 1,024 — — — — — 1,024

Currency translation adjustment — — — — — 3,219 — — — — 3,219

Share-based compensation — — — — 7,723 — — — — — 7,723

Distribution to noncontrolling interest — — — — — — — — — (17,550) (17,550)

Exercise of stock options — — 675 — — — — — — — —

Vesting of restricted stock — — 26,028 1 (1) — — — — — —

Shares withheld — — — — — — — (7,441) (157) — (157)

Currency translation adjustment — — — — — (969) — — — — (969)

________________

The accompanying notes are an integral part of these consolidated financial statements.

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NCS MULTISTAGE HOLDINGS, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)



 Year Ended December 31,

Cash flows from operating activities

Adjustments to reconcile net loss to net cash provided by operating activities:

Amortization of deferred loan cost 296 312 334

(Gain) loss on sale of property and equipment (592) (312) 74

Write-off of deferred loan costs 606 — —

Gain on patent infringement settlement (25,678) — —

Change in fair value of contingent consideration — 37 (2,872)

Net proceeds from patent infringement settlement 21,370 — —

Payment of contingent consideration — (3,042) —

Proceeds from note receivable 302 — —

Changes in operating assets and liabilities:

Prepaid expenses and other assets (3,022) 488 (624)

Cash flows from investing activities

Purchase and development of software and technology (55) (251) (4,675)

Proceeds from sales of property and equipment 1,094 1,372 399

Cash flows from financing activities

Equipment note borrowings — 835 1,988

Payments on equipment note and finance leases (1,513) (5,021) (2,422)

Promissory note borrowings — — 5,360

Payments on promissory note — — (8,673)

Payment of contingent consideration — (6,958) —

Line of credit borrowings 5,000 — —

Proceeds from the exercise of options for common stock, net — — 1,079

Proceeds from the issuance of ESPP shares — 1,024 —

Effect of exchange rate changes on cash and cash equivalents 17 471 (2,164)

Supplemental cash flow information

Cash paid for interest, net of amounts capitalized $ 929 $ 1,070 $ 1,373

Cash paid for income taxes (net of refunds) (1,924) 122 22,356

Noncash investing and financing activities

Return of vehicles under finance lease $ (798) $ — $ —

Changes in accounts payable related to capital expenditures (184) (599) 783

The accompanying notes are an integral part of these consolidated financial statements.