Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis of our financial condition and results of our operations should be read together with our financial statements and the related notes thereto included in this Quarterly Report on Form 10-Q (“Quarterly Report”) and with our audited financial statements and the related notes thereto included in our Annual Report on Form 10-K (“Annual Report”), filed with the Securities and Exchange Commission (the “SEC”). This discussion and analysis contains 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 “Risk Factors.” Our actual results may differ materially from those contained in or implied by these forward-looking statements. As used in this Quarterly Report, except where the context otherwise requires or where otherwise indicated, the terms “Company,” “NCS,” “we,” “our” and “us” refer to NCS Multistage Holdings, Inc.
Overview and Outlook
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 exploration and production (“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 have provided our products and services to various customers, 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 sell products for well construction, including our AirLock casing buoyancy system, liner hanger systems and toe initiation sleeves. We provide tracer diagnostics services for well completion and reservoir characterization that utilize downhole chemical and radioactive tracers and consult on reservoir strategies by providing engineering services. We own a 50% interest in Repeat Precision, LLC (“Repeat Precision”), which sells composite frac plugs and related products and provides third-party manufacturing services. We operate in one reportable segment.
Based on capital budgets set by E&P companies and capital spending incurred by E&P companies year-to-date, we believe that industry drilling and completions activity in North America will be lower in 2019 than it was in 2018. Many of our customers in North America are prioritizing free cash flow and the return of capital to shareholders over production growth, which is leading to lower levels of capital expenditures. This is due to relatively low commodity prices at the time our customers established their budgets, concerns over global demand for oil and natural gas based on macroeconomic conditions and the perceived shareholder preference for E&P companies to spend within cash flow and improve returns on invested capital. We expect customer activity in the U.S. to decline on a year-over-year basis, with activity levels continuing to decline throughout 2019 from year-end 2018 and current levels. With the reduction in industry activity, we are experiencing increased competition across all of our product and services offerings in the United States, which is negatively impacting our market share and margins. We believe that customer activity in Canada in 2019 will continue to be significantly below activity levels in prior years. This is due to the factors mentioned above and to mandatory production curtailments that continue to be imposed on certain operators in Alberta. Market conditions in Canada have resulted in continued customer and competitor-driven pricing pressure for our products and services, negatively impacting our margins and market share in certain markets. We currently expect international activity to increase slightly in 2019 as compared to 2018 as market conditions remain more constructive than in North America.
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 falling to approximately $45 per barrel in December 2018 before recovering to approximately $54 per barrel by the end of September 2019. Crude oil pricing has been supported by voluntary oil production reductions by members of the Organization of Petroleum Exporting Countries (“OPEC”), and certain other countries,
including Russia. Most recently, in response to continued concern over global demand and high global inventory levels, OPEC and certain other countries, including Russia, agreed to extend the supply reductions that have been in place since early 2019 through March 31, 2020. There can be no assurance that the countries involved will continue to comply with the intended reductions and the amount of oil supply that may be returned to the market if the supply reductions are not extended further is unknown.
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. Other oil exporting countries, including Saudi Arabia and Russia may increase oil supplies to offset any shortfall related to a reduction in Iranian oil exports.
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 is placed into service. In Canada, the Province of Alberta implemented measures intended to reduce the differential in the region, including the implementation of mandatory production curtailments for companies producing more than 10,000 barrels per day in the province, which are expected to be in place through the end of 2019 and may continue into 2020.
Natural gas pricing was at an average level of $3.15 per MMBtu during 2018 but has fallen to an average level of $2.38 per MMBtu during the third quarter of 2019 as supply growth has exceeded demand growth. 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. Some Canadian E&P customers have reacted to the lower prices by shutting in a portion of their natural gas production, negatively impacting their cash flows, capital spending and drilling activity.
Sustained declines in commodity prices, or sustained periods of 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:
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Average Price
|
Quarter Ended
|
|
WTI Crude
(per Bbl)
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|
Brent Crude
(per Bbl)
|
|
Henry Hub Natural Gas
(per MMBtu)
|
9/30/2018
|
|
$
|
69.69
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|
$
|
75.07
|
|
$
|
2.93
|
12/31/2018
|
|
|
59.97
|
|
|
68.76
|
|
|
3.77
|
3/31/2019
|
|
|
54.82
|
|
|
63.10
|
|
|
2.92
|
6/30/2019
|
|
|
59.88
|
|
|
69.04
|
|
|
2.57
|
9/30/2019
|
|
|
56.34
|
|
|
61.95
|
|
|
2.38
|
Listed and depicted below are the average number of operating onshore rigs in the U.S. and in Canada per quarter since the third quarter of 2018, as provided by Baker Hughes Company (“Baker Hughes”). The quarterly changes in the Canadian land rig count can be partially attributed to seasonality of activity in that market:
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|
Average Drilling Rig Count
|
Quarter Ended
|
|
U.S. Land
|
|
Canada Land
|
|
North America Land
|
9/30/2018
|
|
1,032
|
|
207
|
|
1,239
|
12/31/2018
|
|
1,050
|
|
177
|
|
1,227
|
3/31/2019
|
|
1,023
|
|
181
|
|
1,204
|
6/30/2019
|
|
967
|
|
79
|
|
1,046
|
9/30/2019
|
|
894
|
|
130
|
|
1,024
|
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. Declines have continued, with the rig count having decreased during the third quarter of 2019 from the second quarter of 2019 by 7%. The average rig count in Canada for the third quarter of 2019 was 37% lower than in the same period in 2018.
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. We anticipate that activity in Canada in the fourth quarter of 2019 will be significantly lower than in the same period of prior years due to reduced customer budgets and production curtailments that are currently in place in Alberta.
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 have
been partially offset by the initiatives implemented by the Province of Alberta. As a result, industry activity and capital spending in Canada in 2019 has been, and is currently forecasted to be, materially below 2018 levels, both for producers of oil and liquids-rich natural gas and producers of natural gas. During the ten months ended October 31, 2019, the average land drilling rig count in Canada, as provided by Baker Hughes, was 32% lower than in the same period in 2018. Commodity price differentials are forecasted to remain at elevated levels for an extended period of time, which we expect to have a negative impact on customer activity in 2019 and beyond.
The industry experienced a reduction in completions activity in the United States in the second half of 2018, which has extended into 2019. In addition, capital budgets from E&P companies indicate that capital spending in 2019 is expected to be below capital spending in 2018, with a number of customers taking steps to reduce the number of rigs and completion crews that they are operating throughout the year. We currently anticipate a further reduction in customer activity during the fourth quarter of 2019.
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 the majority of our revenues from the sale of our fracturing systems products and the provision of related services. The remainder of our revenues are generated from sales of our AirLock casing buoyancy system, liner hanger systems and toe initiation sleeves products and tracer diagnostics and reservoir strategies services. Repeat Precision generates revenue through the sale of composite frac plugs and related products and the provision of third-party manufacturing services.
Product sales represented 72% and 71% of our revenue for the three months ended September 30, 2019 and 2018, respectively, and 72% and 69% for the nine months ended September 30, 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 28% and 29% of our revenues for the three months ended September 30, 2019 and 2018, respectively, and 28% and 31% for the nine months ended September 30, 2019 and 2018, respectively. Services include our tool charges and associated services related to our fracturing systems, reservoir strategies consulting and our tracer diagnostics services and Repeat Precision’s provision of third-party manufacturing (which are classified together as “services” in our financial results). Services are provided at agreed rates we charge to our customers for the provision of our downhole frac isolation assembly, our personnel and for the provision of tracer diagnostics services.
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.
The percentages of our revenue derived from sales in Canada and denominated in Canadian dollars were approximately 43% and 47% for the three months ended September 30, 2019 and 2018, respectively, and approximately 41% and 51% for the nine months ended September 30, 2019 and 2018, respectively. 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 do 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 our company, 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 components used in our products 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 resulted 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. We will strive to pass through some of the increases in raw material costs directly resulting from the tariffs to our customers, however 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 and revaluation or scrap related to our existing inventory and costs related to the chemicals and laboratory analysis associated with our tracer diagnostics services.
Our selling, general and administrative (“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, software licensing, advertising and marketing, third party research and development, risk insurance and professional service fees for audit, legal and other consulting services. As a result of being a public company, our legal, accounting and other expenses have increased and will 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 were approximately 22% and 26% for the three months ended September 30, 2019 and 2018, respectively, and approximately 20% and 23% for the nine months ended September 30, 2019 and 2018, respectively.
Results of Operations
Three Months Ended September 30, 2019 compared to Three Months Ended September 30, 2018
The following table summarizes our revenues and expenses for the period presented (dollars in thousands):
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|
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|
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|
|
|
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|
|
|
|
|
|
Three Months Ended
|
|
|
|
|
|
|
|
|
September 30,
|
|
Variance
|
|
|
2019
|
|
2018
|
|
$
|
|
%
|
Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
Product sales
|
|
$
|
43,756
|
|
$
|
44,633
|
|
$
|
(877)
|
|
(2.0)
|
%
|
Services
|
|
|
17,017
|
|
|
18,058
|
|
|
(1,041)
|
|
(5.8)
|
%
|
Total revenues
|
|
|
60,773
|
|
|
62,691
|
|
|
(1,918)
|
|
(3.1)
|
%
|
Cost of sales
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of product sales, exclusive of depreciation and amortization expense shown below
|
|
|
23,796
|
|
|
20,275
|
|
|
3,521
|
|
17.4
|
%
|
Cost of services, exclusive of depreciation and amortization expense shown below
|
|
|
8,413
|
|
|
8,542
|
|
|
(129)
|
|
(1.5)
|
%
|
Total cost of sales, exclusive of depreciation and amortization expense shown below
|
|
|
32,209
|
|
|
28,817
|
|
|
3,392
|
|
11.8
|
%
|
Selling, general and administrative expenses
|
|
|
20,441
|
|
|
19,356
|
|
|
1,085
|
|
5.6
|
%
|
Depreciation
|
|
|
1,461
|
|
|
1,174
|
|
|
287
|
|
24.4
|
%
|
Amortization
|
|
|
1,153
|
|
|
3,255
|
|
|
(2,102)
|
|
(64.6)
|
%
|
Change in fair value of contingent consideration
|
|
|
—
|
|
|
(1,865)
|
|
|
1,865
|
|
100.0
|
%
|
Income from operations
|
|
|
5,509
|
|
|
11,954
|
|
|
(6,445)
|
|
(53.9)
|
%
|
Other income (expense)
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense, net
|
|
|
(424)
|
|
|
(317)
|
|
|
(107)
|
|
(33.8)
|
%
|
Other income, net
|
|
|
259
|
|
|
28
|
|
|
231
|
|
NM
|
%
|
Foreign currency exchange loss
|
|
|
(131)
|
|
|
(688)
|
|
|
557
|
|
81.0
|
%
|
Total other expense
|
|
|
(296)
|
|
|
(977)
|
|
|
681
|
|
69.7
|
%
|
Income before income tax
|
|
|
5,213
|
|
|
10,977
|
|
|
(5,764)
|
|
(52.5)
|
%
|
Income tax (benefit) expense
|
|
|
(1,396)
|
|
|
3,211
|
|
|
(4,607)
|
|
(143.5)
|
%
|
Net income
|
|
|
6,609
|
|
|
7,766
|
|
|
(1,157)
|
|
(14.9)
|
%
|
Net income attributable to noncontrolling interest
|
|
|
2,988
|
|
|
1,443
|
|
|
1,545
|
|
107.1
|
%
|
Net income attributable to NCS Multistage Holdings, Inc.
|
|
$
|
3,621
|
|
$
|
6,323
|
|
$
|
(2,702)
|
|
(42.7)
|
%
|
_______________
|
(1)
|
|
NM – Percentage not meaningful
|
Revenues
Revenues were $60.8 million for the three months ended September 30, 2019 as compared to $62.7 million for the three months ended September 30, 2018. This decrease was primarily attributable to a decrease in the volume of sales of our fracturing systems products and services and our well construction products in the U.S., partially offset by increased sales of our Repeat Precision products. Product sales for the three months ended September 30, 2019 were $43.8 million as compared to $44.6 million for the three months ended September 30, 2018. Our service revenue was $17.0 million for the three months ended September 30, 2019 as compared to $18.1 million for the three months ended September 30, 2018.
Cost of sales
Cost of sales was $32.2 million, or 53.0% of revenues, for the three months ended September 30, 2019 as compared to $28.8 million, or 46.0% of revenues, for the three months ended September 30, 2018. Cost of sales was a higher percentage of revenues due to reductions in the pricing of our products and services, the use of third-party machining capacity, and higher cost of sales in tracer diagnostics, related to field service staffing levels and increased chemical costs associated with tariffs imposed on certain imports from China in September 2018 and later increased in May 2019. These increases were partially offset by increased sales at Repeat Precision, which enabled better fixed cost utilization. Cost of product sales was $23.8 million, or 54.4% of product sales revenue, and cost of services was $8.4 million, or 49.4% of service revenue, for the three months ended September 30, 2019. For the three months ended September 30, 2018, cost of product sales was $20.3 million, or 45.4% of product sales revenue, and cost of services was $8.5 million, or 47.3% of service revenue.
Selling, general and administrative expenses
Selling, general and administrative expenses were $20.4 million for the three months ended September 30, 2019 as compared to $19.4 million for the three months ended September 30, 2018. The increase was due to higher professional services expenses, most notably litigation expenses, and a one-time severance charge of $0.7 million related to a reduction in workforce, partially offset by lower research and development expenses.
Depreciation
Depreciation was $1.5 million for the three months ended September 30, 2019 as compared to $1.2 million for the three months ended September 30, 2018. The increase is primarily attributable to capital expenditures made during 2018.
Amortization
Amortization was $1.2 million for the three months ended September 30, 2019 as compared to $3.3 million for the three months ended September 30, 2018. The decrease in amortization was related to non-cash impairment charges of $73.5 million in customer relationships and technology during the fourth quarter of 2018, which reduced the carrying values of those intangible assets.
Change in fair value of contingent consideration
We had no change in fair value of contingent consideration for the three months ended September 30, 2019. Change in fair value of contingent consideration was $(1.9) million for the three months ended September 30, 2018 due to the revaluation of the earn-out obligations for Repeat Precision and Spectrum Tracer Services, LLC (“Spectrum”), of which the fair value measures included the impact of both actual results and forecasted future earnings at the time.
Foreign currency exchange loss
Foreign currency exchange loss was $(0.1) million for the three months ended September 30, 2019 as compared to a loss of $(0.7) million for the three months ended September 30, 2018. The change was primarily due to the movement in the foreign currency exchange rates between the periods.
Income tax (benefit) expense
Income tax (benefit) expense was $(1.4) million for the three months ended September 30, 2019 as compared to $3.2 million for the three months ended September 30, 2018. Included in tax expense for the three months ended September 30, 2019 was a valuation allowance against our U.S. deferred tax asset based on management’s position that we have not met the more likely than not condition of realizing the deferred tax asset based on the existence of sufficient projected U.S. taxable income of the appropriate character to recognize the tax benefit as well as the tax effect of a non-deductible goodwill impairment. These adjustments resulted in additional tax (benefit) in the amount of approximately $(6.9) million for the three months ended September 30, 2019. For the three months ended September 30, 2018, our effective income tax rate was 29.3%. The income tax expense and effective tax rate for the three months ended September 30, 2018 was impacted by the U.S. Tax Cuts and Jobs Act of 2017 (the “2017 Tax Act”).
The 2017 Tax Act significantly changes how the U.S. taxes corporations. The 2017 Tax Act requires complex computations to be performed that were not previously required by U.S. tax law, significant judgments to be made in interpretation of the provisions of the 2017 Tax Act, significant estimates in calculations, and the preparation and analysis of information not previously relevant or regularly produced. The ultimate impact of the 2017 Tax Act may differ from our estimates, possibly materially, due to changes in the interpretations and assumptions made as well as additional regulatory guidance that may be issued and actions we may take as a result of the 2017 Tax Act.
The 2017 Tax Act was signed into law on December 22, 2017. The 2017 Tax Act significantly revised the U.S. corporate income tax by, among other things, lowering the statutory corporate tax rate from 35% to 21%, eliminating certain deductions, imposing a mandatory one-time tax on accumulated earnings of foreign subsidiaries as of 2017, introducing new tax regimes, and changing how foreign earnings are subject to U.S. tax. Our preliminary estimate of the 2017 Tax Act and the remeasurement of our deferred tax assets and liabilities is subject to the finalization of management’s analysis related to certain matters, such as developing interpretations of the provisions of the 2017 Tax Act, changes to certain estimates and the filing of our tax returns. U.S. Treasury regulations, administrative interpretations or court decisions interpreting the 2017 Tax Act may require further adjustments and changes in our estimates. Those adjustments may impact our provision for income taxes in the period in which the adjustments are made.
For our calendar year beginning in 2018 we are subject to several provisions of the 2017 Tax Act including computations under Global Intangible Low Taxed Income (“GILTI”) and Foreign Derived Intangible Income (“FDII”). We were able to make a reasonable estimate of the impact of each provision of the 2017 Tax Act on our effective tax rate for the three months ended September 30, 2019 and 2018.
On a longer term basis, certain aspects of the 2017 Tax Act are expected to have a positive impact on our future income tax expense, including the reduction in the U.S. corporate income tax rate.
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.
Nine Months Ended September 30, 2019 compared to Nine Months Ended September 30, 2018
The following table summarizes our revenues and expenses for the period presented (dollars in thousands):
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|
|
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|
Nine Months Ended
|
|
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|
|
|
|
|
|
September 30,
|
|
Variance
|
|
|
2019
|
|
2018
|
|
$
|
|
% (1)
|
|
|
|
(in thousands)
|
|
|
|
|
|
|
Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
Product sales
|
|
$
|
110,933
|
|
$
|
122,514
|
|
$
|
(11,581)
|
|
(9.5)
|
%
|
Services
|
|
|
42,458
|
|
|
54,261
|
|
|
(11,803)
|
|
(21.8)
|
%
|
Total revenues
|
|
|
153,391
|
|
|
176,775
|
|
|
(23,384)
|
|
(13.2)
|
%
|
Cost of sales
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of product sales, exclusive of depreciation and amortization expense shown below
|
|
|
57,032
|
|
|
57,600
|
|
|
(568)
|
|
(1.0)
|
%
|
Cost of services, exclusive of depreciation and amortization expense shown below
|
|
|
25,021
|
|
|
24,721
|
|
|
300
|
|
1.2
|
%
|
Total cost of sales, exclusive of depreciation and amortization expense shown below
|
|
|
82,053
|
|
|
82,321
|
|
|
(268)
|
|
(0.3)
|
%
|
Selling, general and administrative expenses
|
|
|
66,360
|
|
|
62,508
|
|
|
3,852
|
|
6.2
|
%
|
Depreciation
|
|
|
4,382
|
|
|
3,429
|
|
|
953
|
|
27.8
|
%
|
Amortization
|
|
|
3,451
|
|
|
9,859
|
|
|
(6,408)
|
|
(65.0)
|
%
|
Change in fair value of contingent consideration
|
|
|
37
|
|
|
(3,005)
|
|
|
3,042
|
|
101.2
|
%
|
Impairment
|
|
|
7,919
|
|
|
—
|
|
|
7,919
|
|
100.0
|
%
|
(Loss) income from operations
|
|
|
(10,811)
|
|
|
21,663
|
|
|
(32,474)
|
|
(149.9)
|
%
|
Other income (expense)
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense, net
|
|
|
(1,497)
|
|
|
(1,382)
|
|
|
(115)
|
|
(8.3)
|
%
|
Other income, net
|
|
|
349
|
|
|
68
|
|
|
281
|
|
NM
|
%
|
Foreign currency exchange loss
|
|
|
(678)
|
|
|
(399)
|
|
|
(279)
|
|
(69.9)
|
%
|
Total other expense
|
|
|
(1,826)
|
|
|
(1,713)
|
|
|
(113)
|
|
(6.6)
|
%
|
(Loss) income before income tax
|
|
|
(12,637)
|
|
|
19,950
|
|
|
(32,587)
|
|
(163.3)
|
%
|
Income tax expense
|
|
|
10,200
|
|
|
3,137
|
|
|
7,063
|
|
225.2
|
|
Net (loss) income
|
|
|
(22,837)
|
|
|
16,813
|
|
|
(39,650)
|
|
(235.8)
|
%
|
Net income attributable to noncontrolling interest
|
|
|
7,809
|
|
|
3,565
|
|
|
4,244
|
|
119.0
|
%
|
Net (loss) income attributable to NCS Multistage Holdings, Inc.
|
|
$
|
(30,646)
|
|
$
|
13,248
|
|
$
|
(43,894)
|
|
(331.3)
|
%
|
_______________
|
(2)
|
|
NM – Percentage not meaningful
|
Revenues
Revenues were $153.4 million for the nine months ended September 30, 2019 as compared to $176.8 million for the nine months ended September 30, 2018. This decrease was primarily attributable to a decrease in the volume of sales of our fracturing systems products and services, especially in the U.S. and Canada and lower tracer diagnostics revenue in the U.S., partially offset by increased sales of our well construction and Repeat Precision products. Product sales for the nine months ended September 30, 2019 were $110.9 million as compared to $122.5 million for the nine months ended September 30, 2018. Our service revenue was $42.5 million for the nine months ended September 30, 2019 as compared to $54.3 million for the nine months ended September 30, 2018.
Cost of sales
Cost of sales was $82.1 million, or 53.5% of revenues, for the nine months ended September 30, 2019 as compared to $82.3 million, or 46.6% of revenues, for the nine months ended September 30, 2018. Cost of sales was a higher percentage of revenues due to reduced fixed cost utilization related to lower sales volumes for fracturing systems products and services, especially in the U.S. and Canada, reductions in the pricing of our products and services, higher-than-anticipated use of third-party machining capacity in 2019, and higher cost of sales in tracer diagnostics, related to field service staffing levels and increased chemical costs associated with tariffs imposed on certain imports from China in September 2018 and later increased in May 2019. These increases were partially offset by increased sales of well construction products and increased sales at Repeat Precision, which enabled better fixed cost utilization. Cost of product sales was $57.0 million, or 51.4% of product sales revenue, and cost of services was $25.0 million, or 58.9% of service revenue, for the nine months ended September 30, 2019. For the nine months ended September 30, 2018, cost of product sales was $57.6 million, or 47.0% of product sales revenue, and cost of services was $24.7 million, or 45.6% of service revenue.
Selling, general and administrative expenses
Selling, general and administrative expenses were $66.4 million for the nine months ended September 30, 2019 as compared to $62.5 million for the nine months ended September 30, 2018. The increase was due to higher professional services expenses, most notably litigation expenses, and support for our new enterprise resource planning (“ERP”) system, higher share-based compensation expense, a one-time severance charge of $0.7 million related to a reduction in workforce and an increase in bad debt expense, partially offset by lower compensation and research and development expenses.
Depreciation
Depreciation was $4.4 million for the nine months ended September 30, 2019 as compared to $3.4 million for the nine months ended September 30, 2018. The increase is primarily attributable to capital expenditures made during 2018.
Amortization
Amortization was $3.5 million for the nine months ended September 30, 2019 as compared to $9.9 million for the nine months ended September 30, 2018. The decrease in amortization was related to non-cash impairment charges of $73.5 million in customer relationships and technology during the fourth quarter of 2018, which reduced the carrying values of those intangible assets.
Change in fair value of contingent consideration
Change in fair value of contingent consideration was $37 thousand for the nine months ended September 30, 2019 compared to $(3.0) million for the nine months ended September 30, 2018. The change for the nine months ended September 30, 2019 was related to the passage of time from December 31, 2018 to January 31, 2019 when the $10.0 million cash payment for the Repeat Precision earn-out was paid to the joint venture partner. No payment was made for the Spectrum earnout. The change for the nine months ended September 30, 2018 was due to the revaluation of the earn-out obligations for Repeat Precision and Spectrum, of which the fair value measures included the impact of both actual results and forecasted future earnings at the time.
Impairment
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 market share 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 third quarter of 2019. See “Note 5. Goodwill and Intangibles” of our consolidated financial statements for additional detail.
Income tax expense
Income tax expense was $10.2 million for the nine months ended September 30, 2019 as compared to $3.1 million for the nine months ended September 30, 2018. Included in tax expense for the nine months ended September 30, 2019 was a valuation allowance against our U.S. deferred tax asset based on management’s position that we have not met the more likely than not condition of realizing the deferred tax asset based on the existence of sufficient projected U.S. taxable income of the appropriate character to recognize the tax benefit as well as the tax effect of a non-deductible goodwill impairment. These adjustments resulted in additional tax expense in the nine months ended September 30, 2019 of approximately $11.7 million. The income tax expense and effective tax rate for the nine months ended September 30, 2018 was significantly impacted by the 2017 Tax Act including administrative guidance
issued by the Internal Revenue Service on April 2, 2018. This guidance resulted in a final change to the calculation of the mandatory one-time tax on accumulated earnings of foreign subsidiaries in the 2017 tax return filing and a tax benefit of $2.1 million for the nine months ended September 30, 2018 was recorded in tax expense with a corresponding reduction in the effective tax rate of 10.6%
The 2017 Tax Act significantly changes how the U.S. taxes corporations. The 2017 Tax Act requires complex computations to be performed that were not previously required by U.S. tax law, significant judgments to be made in interpretation of the provisions of the 2017 Tax Act, significant estimates in calculations, and the preparation and analysis of information not previously relevant or regularly produced. The ultimate impact of the 2017 Tax Act may differ from our estimates, possibly materially, due to changes in the interpretations and assumptions made as well as additional regulatory guidance that may be issued and actions we may take as a result of the 2017 Tax Act.
The 2017 Tax Act was signed into law on December 22, 2017. The 2017 Tax Act significantly revised the U.S. corporate income tax by, among other things, lowering the statutory corporate tax rate from 35% to 21%, eliminating certain deductions, imposing a mandatory one-time tax on accumulated earnings of foreign subsidiaries as of 2017, introducing new tax regimes, and changing how foreign earnings are subject to U.S. tax. Our preliminary estimate of the 2017 Tax Act and the remeasurement of our deferred tax assets and liabilities is subject to the finalization of management’s analysis related to certain matters, such as developing interpretations of the provisions of the 2017 Tax Act, changes to certain estimates and the filing of our tax returns. U.S. Treasury regulations, administrative interpretations or court decisions interpreting the 2017 Tax Act may require further adjustments and changes in our estimates. Those adjustments may impact our provision for income taxes in the period in which the adjustments are made.
For our calendar year beginning in 2018 we are subject to several provisions of the 2017 Tax Act including computations under GILTI and FDII. We were able to make a reasonable estimate of the impact of each provision of the 2017 Tax Act on our effective tax rate for the nine months ended September 30, 2019 and 2018.
On a longer term basis, certain aspects of the 2017 Tax Act are expected to have a positive impact on our future income tax expense, including the reduction in the U.S. corporate income tax rate.
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 New Senior Secured Credit Facility (defined below). As of September 30, 2019, we had cash and cash equivalents of $4.5 million and potential availability under the New Senior Secured Credit Facility of $62.0 million. Our total indebtedness was $16.3 million as of September 30, 2019. The New Senior Secured Credit Facility consists of revolving credit facilities in aggregate principal amount of $75.0 million. Our principal liquidity needs have been, and are expected to continue to be, capital expenditures, working capital, debt service and potential mergers and acquisitions.
Our capital expenditures for the nine months ended September 30, 2019 and 2018 were $5.2 million and $9.9 million, respectively. We plan to incur approximately $6.0 million to $7.0 million in capital expenditures during 2019, which includes capital expenditures related to (i) additional machining capacity at Repeat Precision, (ii) additional production equipment and instrumentation to support tracer diagnostics services, (iii) machinery and equipment utilized in manufacturing and engineering and (iv) our research and development facility. We believe our cash on hand, cash flows from operations and potential borrowings under our New Senior Secured Credit Facility will be sufficient to fund our capital expenditure and liquidity requirements for the next twelve months.
We anticipate that to the extent that we require additional liquidity, 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 meet our obligations and fund our capital requirements are also dependent on our future financial performance, which is subject to general economic, financial and other factors that are beyond our control. 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
The following table provides a summary of cash flows from operating, investing and financing activities for the periods presented (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended
|
|
|
September 30,
|
|
|
2019
|
|
2018
|
Net cash provided by operating activities
|
|
$
|
4,815
|
|
$
|
7,615
|
Net cash used in investing activities
|
|
|
(4,425)
|
|
|
(9,642)
|
Net cash used in financing activities
|
|
|
(21,251)
|
|
|
(3,409)
|
Effect of exchange rate changes on cash and cash equivalents
|
|
|
248
|
|
|
(933)
|
Net change in cash and cash equivalents
|
|
$
|
(20,613)
|
|
$
|
(6,369)
|
Operating Activities
Net cash provided by operating activities was $4.8 million and $7.6 million for the nine months ended September 30, 2019 and 2018, respectively. The reduction in cash flow was primarily driven by lower net income and unfavorable changes in inventories, partially offset by favorable changes in accounts payable, prepaid expenses and other assets, deferred tax (expense) benefit and income tax receivable/payable.
Investing Activities
Net cash used in investing activities was $4.4 million and $9.6 million for the nine months ended September 30, 2019 and 2018, respectively. The decrease in cash used in investing activities during the nine months ended September 30, 2019 as compared to the nine months ended September 30, 2018 was primarily related to capital expenditures, including property, equipment, software and technology, of $5.2 million in the nine months ended September 30, 2019 compared to $9.9 million for the same period in 2018.
Financing Activities
Net cash used in financing activities was $21.3 million and $3.4 million for the nine months ended September 30, 2019 and 2018, 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 $7.0 million on our New Senior Secured Credit Facility (as defined below) during the second and third quarters of 2019 and made distributions to our joint venture partner of $3.4 million during the nine months ended September 30, 2019 as compared to $0.5 million of distributions for the same period in 2018.
Financing Arrangements
Prior Senior Secured Credit Facility
On May 4, 2017, we entered into an Amended and Restated Credit Agreement (the “Prior Credit Agreement”) with Pioneer Investment, Inc., as borrower (the “U.S. Borrower”), NCS Multistage Inc., as borrower (the “Canadian Borrower”), Pioneer Intermediate, Inc. (together with the Company, the “Parent Guarantors”) and the lenders party thereto, Wells Fargo Bank, National Association as administrative agent in respect of the Prior U.S. Facility (as defined below) and Wells Fargo Bank, National Association, Canadian Branch as administrative agent in respect of the Prior Canadian Facility (as defined below) (the senior secured revolving credit facilities provided thereunder, the “Prior Senior Secured Credit Facility”).
The Prior Senior Secured Credit Facility consisted of a (i) senior secured revolving credit facility in an aggregate principal amount of $50.0 million made available to the U.S. Borrower (the “Prior U.S. Facility”), of which up to $5.0 million could be made available for letters of credit and up to $5.0 million could be made available for swingline loans and (ii) senior secured revolving credit facility in an aggregate principal amount of $25.0 million made available to the Canadian Borrower (the “Prior Canadian Facility”). We amended and restated the Prior Senior Secured Credit Facility. See “Note 7. Debt” to our unaudited condensed consolidated financial statements for additional details regarding our Prior Senior Secured Credit Facility.
New Senior Secured Credit Facility
On May 1, 2019, we entered into a Second Amended and Restated Credit Agreement (the “New Credit Agreement”) with Pioneer Investment, Inc., as U.S. borrower, NCS Multistage Inc., as Canadian borrower, Pioneer Intermediate, Inc. and the lenders party thereto, Wells Fargo Bank, National Association as administrative agent in respect of the New U.S. Facility (as defined below) and Wells Fargo Bank, National Association, Canadian Branch, as administrative agent in respect of the New Canadian Facility (as defined below) (the senior secured revolving credit facilities provided thereunder, the “New Senior Secured Credit Facility”). The New Credit Agreement amended and restated the Prior Credit Agreement in its entirety.
The New Senior Secured Credit Facility consists of a (i) senior secured revolving credit facility in an aggregate principal amount of $50.0 million made available to the U.S. Borrower (the “New U.S. Facility”), of which up to $5.0 million may be made available for letters of credit and up to $5.0 million may be made available for swingline loans and (ii) senior secured revolving credit facility in an aggregate principal amount of $25.0 million made available to the Canadian Borrower (the “New Canadian Facility”). The New Senior Secured Credit Facility will mature on May 1, 2023. At September 30, 2019, we had $13.0 million in outstanding indebtedness under the New U.S. Facility and no outstanding indebtedness under the New Canadian Facility.
Borrowings under the New U.S. Facility may be made in U.S. dollars for Adjusted Base Rate Advances, and in U.S. dollars, Canadian dollars or Euros for Eurocurrency Rate Advances (each as defined in the New Credit Agreement). Such advances bear interest at the Adjusted Base Rate or at the Eurocurrency Rate plus an applicable interest margin as set forth in the New Credit Agreement. Borrowings under the New Canadian Facility may be made in U.S. dollars or Canadian dollars and bear interest at the Canadian (Cdn) Base Rate, Canadian (U.S.) Base Rate, Eurocurrency Rate or Discount Rate (each as defined in the New Credit Agreement), in each case, plus an applicable interest margin as set forth in the New Credit Agreement. The Adjusted Base Rate, Canadian (U.S.) Base Rate, Canadian (Cdn) Base Rate and Eurocurrency Rate applicable margin will be between 2.75% and 3.50%, in each case, depending on the Company’s leverage ratio. The applicable interest rate at September 30, 2019 was 5.125%.
The obligations of the U.S. Borrower under the New U.S. Facility are guaranteed by the Parent Guarantors and each of the other existing and future direct and indirect restricted subsidiaries of the Company organized under the laws of the United States (subject to certain exceptions) and are secured by substantially all of the assets of the Parent Guarantors, the U.S. Borrower and such other subsidiary guarantors, in each case, subject to certain exceptions and permitted liens. The obligations of the Canadian Borrower under the New Canadian Facility are guaranteed by the Parent Guarantors, the U.S. Borrower and each of the other future direct and indirect restricted subsidiaries of the Company 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 U.S. Borrower, the Canadian Borrower and such other subsidiary guarantors, in each case, subject to certain exceptions and permitted liens.
The New Credit Agreement contains financial covenants that require (i) commencing with the fiscal quarter ending June 30, 2019, compliance with a maximum leverage ratio test set at 2.50 to 1.00 as of the last day of each fiscal quarter, (ii) commencing with the fiscal quarter ending June 30, 2019, compliance with an interest coverage ratio test set at not more than 2.75 to 1.00 as of the last day of each fiscal quarter, (iii) if the leverage ratio as of the end of any fiscal quarter is greater than 2.00 to 1.00 and the amount outstanding under the New Canadian Facility at any time during such fiscal quarter was greater than $0, compliance as of the end of such fiscal quarter with a Canadian asset coverage ratio test of at least 1.00 to 1.00 and (iv) if the leverage ratio as of the end of any fiscal quarter is greater than 2.00 to 1.00 and the amount outstanding under the New U.S. Facility at any time during such fiscal quarter was greater than $0, compliance as of the end of such fiscal quarter with a U.S. asset coverage ratio test of at least 1.00 to 1.00. As of September 30, 2019, we were in compliance with these financial covenants. The New 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 New Credit Agreement also includes customary events of default for facilities of this type (with customary grace periods, as applicable). If an event of default occurs, the lenders under each of the New U.S. Facility and the New Canadian Facility 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 under each of the New U.S. Facility and the New Canadian Facility also have the right upon an event of default thereunder to terminate any commitments they have to provide further borrowings under such facility. Further, following an event of default under each of the New U.S. Facility and the New Canadian Facility, the lenders thereunder will have the right to proceed against the collateral granted to them to secure such facility.
Contractual Obligations
There have been no material changes in our contractual obligations and commitments disclosed in the Annual Report for the year ended December 31, 2018.
Off-Balance Sheet Arrangements
We have no off-balance sheet financing arrangements.
Critical Accounting Policies
See “Note 1. Basis of Presentation” to our unaudited condensed consolidated financial statements for our new significant accounting policy. We have also updated our lease accounting policies in conjunction with our adoption of ASU 2016-02 and its related amendments (collectively known as “ASC 842”) as further described in “Note 8. Leases” in our unaudited condensed consolidated financial statements. There are no other material changes to our critical accounting policies from those included in the Annual Report for the year ended December 31, 2018.
Recently Issued Accounting Pronouncements
See “Note 1. Basis of Presentation” to our unaudited condensed consolidated financial statements for discussion of the accounting pronouncement we recently adopted and the accounting pronouncements recently issued by the Financial Accounting Standards Board.
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 initial public offering, (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 Securities Exchange Act of 1934, as amended (“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.
Cautionary Note Regarding Forward-Looking Statements
This Quarterly Report contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. Forward-looking statements can be identified by words such as “anticipates,” “intends,” “plans,” “seeks,” “believes,” “estimates,” “expects” and similar references to future periods, or by the inclusion of forecasts or projections. Examples of forward-looking statements include, but are not limited to, statements we make regarding the outlook for our future business and financial performance, such as those contained in this Item 2. “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
Forward-looking statements are based on our current expectations and assumptions regarding our business, the economy and other future conditions. Because forward-looking statements relate to the future, by their nature, they are subject to inherent uncertainties, risks and changes in circumstances that are difficult to predict. As a result, our actual results may differ materially from those contemplated by the forward-looking statements. Important factors that could cause our actual results to differ materially from those in the forward-looking statements include regional, national or global political, economic, business, competitive, market and regulatory conditions and the following:
|
·
|
|
declines in the level of oil and natural gas exploration and production activity within Canada and the United States;
|
|
·
|
|
oil and natural gas price fluctuations;
|
|
·
|
|
loss of significant customers;
|
|
·
|
|
inability to successfully implement our strategy of increasing sales of products and services into the United States;
|
|
·
|
|
significant competition for our products and services;
|
|
·
|
|
our inability to accurately predict customer demand;
|
|
·
|
|
impairment in the carrying value of long-lived assets and goodwill;
|
|
·
|
|
our inability to successfully develop and implement new technologies, products and services;
|
|
·
|
|
our inability to protect and maintain critical intellectual property assets;
|
|
·
|
|
currency exchange rate fluctuations;
|
|
·
|
|
losses and liabilities from uninsured or underinsured business activities;
|
|
·
|
|
our failure to identify and consummate potential acquisitions;
|
|
·
|
|
our inability to integrate or realize the expected benefits from acquisitions;
|
|
·
|
|
impact of severe weather conditions;
|
|
·
|
|
restrictions on the availability of our customers to obtain water essential to the drilling and hydraulic fracturing processes;
|
|
·
|
|
our inability to meet regulatory requirements for use of certain chemicals by our tracer diagnostics business;
|
|
·
|
|
change in trade policy, including the impact of additional tariffs;
|
|
·
|
|
changes in legislation or regulation governing the oil and natural gas industry, including restrictions on emissions of greenhouse gases;
|
|
·
|
|
failure to comply with or changes to federal, state and local and non-U.S. laws and other regulations, including environmental regulations and the 2017 Tax Act;
|
|
·
|
|
loss of our information and computer systems;
|
|
·
|
|
system interruptions or failures, including cyber-security breaches, identity theft or other disruptions that could compromise our information;
|
|
·
|
|
our failure to establish and maintain effective internal control over financial reporting;
|
|
·
|
|
complications with the design and implementation of our new enterprise resource planning system;
|
|
·
|
|
our success in attracting and retaining qualified employees and key personnel; and
|
|
·
|
|
our inability to satisfy technical requirements and other specifications under contracts and contract tenders.
|
For the reasons described above, as well as factors identified in “Item 1A. Risk Factors” in this Quarterly Report and the section of the Annual Report entitled “Risk Factors,” we caution you against relying on any forward-looking statements. Any forward-looking statement made by us in this Quarterly Report speaks only as of the date on which we make it. Factors or events that could cause our actual results to differ may emerge from time to time, and it is not possible for us to predict all of them. We undertake no obligation to publicly update or revise any forward-looking statement, whether as a result of new information, future developments or otherwise, except as may be required by law.