Item 2. Mana
gement’s Discussion and Analysis of Financial Condition and Results of Operation
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
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 and Russia. 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.
In addition to our fracturing systems products and services, we sell other products for well construction, including our AirLock casing buoyancy system and liner hanger systems. We also provide tracer diagnostics for well completion and reservoir characterization that utilize downhole chemical and radioactive tracers and consult on reservoir strategies by providing engineering services.
Repeat Precision, LLC (“Repeat Precision”), sells composite frac plugs and related products and provides third-party manufacturing services.
We operate in one reportable segment.
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 production activity in North America. Oil and natural gas drilling and production activity is directly related to oil and natural gas prices.
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 average U.S. land rig count improved from 874 in the second quarter of 2017 to 1,021 in the second quarter of 2018, while the average rig count in Canada, which exhibits a higher degree of seasonality than the U.S., decreased from 116 in the second quarter of 2017 to 105 in the second quarter of 2018. Over this time, the demand for our products and services has also increased.
Oil and natural gas prices remain volatile, with WTI crude oil pricing falling to below $43 per barrel in June 2017 before recovering to approximately $74 per barrel by the end of June 2018.
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. These supply reductions were announced in November 2016 and were initially implemented in 2017. In November 2017, OPEC and certain other countries, including Russia, announced their intent to extend the supply reductions through the end of 2018.
These countries have reduced their supply by more than the
targeted amounts through early 2018, reaching 152% of targeted supply reductions in May 2018. In June 2018, OPEC and certain other countries, including Russia, announced that they would strive to conform with the supply reductions at a level of 100% as of July 1, 2018, signaling an increase in production from recent levels.
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 beyond the end of 2018 is unknown.
Natural gas pricing has
been more stable, remaining close to $3.00 per mmBtu. 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 wider-than-normal discounts to Henry Hub pricing resulting from infrastructure bottlenecks and elevated local storage levels. 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 and planned capital spending and drilling activity. Sustained declines in commodity prices, combined with potential increases in the cost of drilling and completing wells resulting from high utilization in certain oilfield services categories could lead North American E&P companies to 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)
|
|
Brent Crude
(per bbl)
|
|
Henry Hub Natural Gas
(per mmBtu)
|
6/30/2017
|
|
$
|
48.10
|
|
$
|
49.55
|
|
$
|
3.08
|
9/30/2017
|
|
|
48.15
|
|
|
52.10
|
|
|
2.95
|
12/31/2017
|
|
|
55.27
|
|
|
61.40
|
|
|
2.91
|
3/31/2018
|
|
|
62.91
|
|
|
66.86
|
|
|
3.08
|
6/30/2018
|
|
|
68.07
|
|
|
74.45
|
|
|
2.85
|
Listed and depicted below are the average number of operating onshore rigs in the U.S. and in Canada per quarter since the second quarter of 2017, as provided by Baker Hughes, a GE company:
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Average Drilling Rig Count
|
Quarter Ended
|
|
U.S. Land
|
|
Canada Land
|
|
North America Land
|
6/30/2017
|
|
874
|
|
116
|
|
990
|
9/30/2017
|
|
927
|
|
207
|
|
1,134
|
12/31/2017
|
|
902
|
|
203
|
|
1,105
|
3/31/2018
|
|
965
|
|
267
|
|
1,232
|
6/30/2018
|
|
1,021
|
|
105
|
|
1,126
|
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.
In early 2018, Canada experienced higher than normal levels of precipitation, including snowfall, which resulted in a more protracted seasonal reduction in drilling and completion activity.
Our business can also be impacted by a reduction in customer activity during the winter holidays in late December and early January.
The average Canadian rig count declined in the second quarter of 2018 relative to the second quarter of 2017. We believe this reduction in drilling activity was a result of low recent spot natural gas prices, greater discounts in Canadian crude oil pricing relative to U.S. benchmarks and the impact of the
higher than normal levels of
precipitation experienced in Canada in early 2018.
Based on the current commodity price environment, many U.S. E&P companies have indicated that they expect to increase their drilling and completions budgets in 2018, relative to 2017. In the first quarter of 2018 many E&P and oilfield services companies, including us, noted instances of supply chain disruptions related to material and labor availability, which resulted in temporary delays in planned drilling and completion activity.
In addition, oil production from the Permian Basin is expected to exceed local refining demand and pipeline takeaway capacity from the second half of 2018 through the end of 2019, when additional pipelines are expected to be placed into service. This has led to reduced local crude oil pricing as compared to WTI and Brent-linked benchmarks. Some E&P companies have indicated that they plan to reduce their drilling and completion activity in the Permian Basin as a result of the lower realized prices and temporary limitations on takeaway capacity.
The market in Canada 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, especially those that sell natural gas into the local market. As a result, industry capital spending in Canada in 2018 is currently forecasted to be in line with or below 2017 levels, with higher spending by producers of oil and liquids-rich natural gas offset by declines by producers of natural gas. During the second quarter of 2018, the average land drilling rig count in Canada, as provided by Baker Hughes, was nine percent lower than during the same period in 2017.
We expect that we will be able to leverage our technologically differentiated product and service offerings to continue to grow our business in 2018, especially in the United States, where industry activity is expected to grow and where we have greater opportunities for further market share penetration.
Increasing 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. We believe that pinpoint stimulation provides substantial benefits compared to these traditional well completion techniques and that pinpoint stimulation has become increasingly utilized by operators in North America, particularly in Canada. 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 continued adoption of pinpoint stimulation to complete wells.
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 in support of completion and field development optimization efforts.
How We Generate Revenues
We derive the majority of our revenues f
rom 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 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 64% and 80% of our revenue for the three months ended June 30, 2018 and 2017, respectively, and 68% and 79% for the six months ended June 30, 2018 and 2017, 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 36% and 20% of our revenues for the three months ended June 30, 2018 and 2017, respectively, and 32% and 21% for the six months ended June 30, 2018 and 2017, respectively. Services include our tool charges and associated services
related to our fracturing systems offering and our tracer diagnostics services
(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 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 three months ended June 30, 2018 and 2017, approximately 32% and 45%, respectively, of our revenues were derived from sales in Canada and were denominated in Canadian dollars.
For the six months ended June 30, 2018 and 2017, approximately 54% and 61%, respectively, of our revenues were attributable to our Canadian sales. 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 typically made to our local operating partners on a free on board 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, Russia 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. During the first quarter of 2017, we acquired Repeat Precision, which we believe will allow 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.
While we and our suppliers have locked in pricing for certain raw materials required to support some of our anticipated business activity during 2018, we anticipate that the tariff could result in an increase in our cost of sales, beginning as early as the third quarter of 2018.
We will strive to pass through some, if not all, of the increases in raw material costs directly resulting from the tariff 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 19% and 35% for the three months ended June 30, 2018 and 2017, respectively, and approximately 21% and 31% for the six months ended June 30, 2018 and 2017, respectively.
Results of Operations
We made acquisitions in the first quarter and third quarter of 2017. For additional information about these acquisitions, see “Note 3. Acquisitions”
in
our unaudited condensed consolidated financial statements.
Due to these acquisitions, our results of operations for the 2018 period presented may not be comparable to historical results of operations for the 2017 period. The following table summarizes our revenues and expenses for the periods presented (dollars in thousands):
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|
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
|
|
|
|
Six Months Ended
|
|
|
|
|
|
|
|
|
June 30,
|
|
Variance
|
|
June 30,
|
|
Variance
|
|
|
2018
|
|
2017
|
|
$
|
|
%
|
|
2018
|
|
2017
|
|
$
|
|
%
|
Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Product sales
|
|
$
|
27,773
|
|
$
|
29,397
|
|
$
|
(1,624)
|
|
(5.5)
|
%
|
|
$
|
77,881
|
|
$
|
74,971
|
|
$
|
2,910
|
|
3.9
|
%
|
Services
|
|
|
15,625
|
|
|
7,460
|
|
|
8,165
|
|
109.5
|
%
|
|
|
36,203
|
|
|
20,522
|
|
|
15,681
|
|
76.4
|
%
|
Total revenues
|
|
|
43,398
|
|
|
36,857
|
|
|
6,541
|
|
17.7
|
%
|
|
|
114,084
|
|
|
95,493
|
|
|
18,591
|
|
19.5
|
%
|
Cost of sales
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of product sales, exclusive of depreciation and amortization expense shown below
|
|
|
12,622
|
|
|
15,733
|
|
|
(3,111)
|
|
(19.8)
|
%
|
|
|
37,325
|
|
|
40,448
|
|
|
(3,123)
|
|
(7.7)
|
%
|
Cost of services, exclusive of depreciation and amortization expense shown below
|
|
|
7,290
|
|
|
3,152
|
|
|
4,138
|
|
131.3
|
%
|
|
|
16,179
|
|
|
7,791
|
|
|
8,388
|
|
107.7
|
%
|
Total cost of sales, exclusive of depreciation and amortization expense shown below
|
|
|
19,912
|
|
|
18,885
|
|
|
1,027
|
|
5.4
|
%
|
|
|
53,504
|
|
|
48,239
|
|
|
5,265
|
|
10.9
|
%
|
Selling, general and administrative expenses
|
|
|
22,125
|
|
|
16,163
|
|
|
5,962
|
|
36.9
|
%
|
|
|
43,152
|
|
|
28,935
|
|
|
14,217
|
|
49.1
|
%
|
Depreciation
|
|
|
1,156
|
|
|
678
|
|
|
478
|
|
70.5
|
%
|
|
|
2,255
|
|
|
1,242
|
|
|
1,013
|
|
81.6
|
%
|
Amortization
|
|
|
3,283
|
|
|
5,973
|
|
|
(2,690)
|
|
(45.0)
|
%
|
|
|
6,604
|
|
|
11,995
|
|
|
(5,391)
|
|
(44.9)
|
%
|
Change in fair value of contingent consideration
|
|
|
213
|
|
|
767
|
|
|
(554)
|
|
(72.2)
|
%
|
|
|
(1,140)
|
|
|
767
|
|
|
(1,907)
|
|
(248.6)
|
%
|
(Loss) income from operations
|
|
|
(3,291)
|
|
|
(5,609)
|
|
|
2,318
|
|
41.3
|
%
|
|
|
9,709
|
|
|
4,315
|
|
|
5,394
|
|
125.0
|
%
|
Other income (expense)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense, net
|
|
|
(608)
|
|
|
(2,007)
|
|
|
1,399
|
|
69.7
|
%
|
|
|
(1,065)
|
|
|
(3,516)
|
|
|
2,451
|
|
69.7
|
%
|
Other (expense) income, net
|
|
|
(44)
|
|
|
64
|
|
|
(108)
|
|
(168.8)
|
%
|
|
|
40
|
|
|
1,038
|
|
|
(998)
|
|
(96.1)
|
%
|
Foreign currency exchange gain
|
|
|
106
|
|
|
1,952
|
|
|
(1,846)
|
|
(94.6)
|
%
|
|
|
289
|
|
|
1,011
|
|
|
(722)
|
|
(71.4)
|
%
|
Total other (expense) income
|
|
|
(546)
|
|
|
9
|
|
|
(555)
|
|
(6,166.7)
|
%
|
|
|
(736)
|
|
|
(1,467)
|
|
|
731
|
|
49.8
|
%
|
(Loss) income before income tax
|
|
|
(3,837)
|
|
|
(5,600)
|
|
|
1,763
|
|
31.5
|
%
|
|
|
8,973
|
|
|
2,848
|
|
|
6,125
|
|
215.1
|
%
|
Income tax (benefit) expense
|
|
|
(1,019)
|
|
|
(855)
|
|
|
(164)
|
|
(19.2)
|
%
|
|
|
(74)
|
|
|
1,245
|
|
|
(1,319)
|
|
(105.9)
|
%
|
Net (loss) income
|
|
|
(2,818)
|
|
|
(4,745)
|
|
|
1,927
|
|
40.6
|
%
|
|
|
9,047
|
|
|
1,603
|
|
|
7,444
|
|
464.4
|
%
|
Net income (loss) attributable to noncontrolling interest
|
|
|
1,235
|
|
|
(254)
|
|
|
1,489
|
|
586.2
|
%
|
|
|
2,122
|
|
|
(456)
|
|
|
2,578
|
|
565.4
|
%
|
Net (loss) income attributable to NCS Multistage Holdings, Inc.
|
|
$
|
(4,053)
|
|
$
|
(4,491)
|
|
$
|
438
|
|
9.8
|
%
|
|
$
|
6,925
|
|
$
|
2,059
|
|
$
|
4,866
|
|
236.3
|
%
|
Three Months Ended June 30, 2018 compared to Three Months Ended June 30, 2017
Revenues
Revenues were $43.4 million for the three months ended June 30, 2018 as compared to $36.9 million for the three months ended June 30, 2017. This increase was primarily attributable to an increase in services revenue, including tracer diagnostics services, which we added in 2017 through the acquisition of
Spectrum Tracer Services, LLC (“Spectrum”)
. We also experienced an increase in sales volumes of products utilized in well construction and in composite frac plugs. These increases were offset by lower volumes of
fracturing systems product sales, especially in Canada
, which was impacted by reduced industry activity levels in 2018 as compared to 2017.
Product sales for the three months ended June 30, 2018 were $27.8 million as compared to $29.4 million for the three months ended June 30, 2017. Our service revenue was $15.6 million for the three months ended June 30, 2018 as compared to $7.5 million for the three months ended June 30, 2017.
Cost of sales
Cost of sales was $19.9 million, or 45.9% of revenues, for the three months ended June 30, 2018 as compared to $18.9 million, or 51.2% of revenues, for the three months ended June 30, 2017. The increase in cost of sales was primarily a result of increased revenues for tracer diagnostics services, well construction products and composite frac plugs. Cost of sales was a lower percentage of revenues due to the relative increase in services revenue and higher sales volumes for well construction products and at Repeat Precision, which enabled better utilization of fixed costs.
Cost of product sales was $12.6 million, or 45.4% of product sales revenue, and cost of services was $7.3 million, or 46.7% of service revenue, for the
three months
ended June 30, 2018. For the
three months
ended June 30, 2017, cost of product sales was $15.7 million, or 53.5% of product sales revenue, and cost of services was $3.2 million, or 42.3% of service revenue.
Selling, general and administrative expenses
Selling, general and administrative expenses were $22.1 million for the three months ended June 30, 2018 as compared to $16.2 million for the three months ended June 30, 2017. The increase was the direct result of headcount additions in substantially all functional areas, three months of tracer diagnostics operations resulting from our Spectrum acquisition and an increase in share-based compensation related to
the issuance of restricted stock units and performance stock unit awards as well as amendments to certain stock options in connection with our initial public offering (“IPO”) during the second quarter of 2017
. The increases were partially offset by non-capitalizable additional expenses incurred related to our IPO of $0.8 million and acquisition costs of $0.4 million incurred during the three months ended June 30, 2017.
Depreciation
Depreciation was $1.2 million for the three months ended June 30, 2018 as compared to $0.7 million for the three months ended June 30, 2017. The increase is attributable to a higher level of property and equipment, primarily related to our acquisitions.
Amortization
Amortization was $3.3 million for the three months ended June 30, 2018 as compared to $6.0 million for the three months ended June 30, 2017. The decrease in amortization was related to intangible assets that became fully amortized during the fourth quarter of 2017. The decrease was partially offset by an increase in amortizable intangible assets related to our acquisitions.
Change in fair value of contingent consideration
Change in fair value of contingent consideration was $0.2 million for the three months ended June 30, 2018 and $0.8
million
for the three months ended June 30, 2017 due to the increase in
the fair value of the earn-outs associated with our acquisitions.
Interest expense, net
Interest expense, net was $0.6 million for the three months ended June 30, 2018 as compared to $2.0 million for the three months ended June 30, 2017. The decrease in interest expense, net was primarily a result of prepaying our prior term loan in full in May 2017 by utilizing a portion of the proceeds from our IPO. The decrease was partially offset by higher interest expense due to borrowing $20.0 million under our Senior Secured Credit Facility in August 2017.
Foreign currency exchange gain
Foreign currency exchange gain was $0.1 million for the three months ended June 30, 2018 as compared to a gain of $2.0 million for the three months ended June 30, 2017. The change was primarily due to the impact of the retirement of our foreign currency denominated debt for the three months ended June 30, 2017 and movement in the foreign currency exchange rates between the periods.
Income tax (benefit)
Income tax (benefit) was
$(1.0)
million for the three months ended June 30, 2018 as compared to $(0.9) million for the three months ended June 30, 2017. For the three months ended June 30, 2018 and 2017, our effective income tax rates were (26.6)% and
(15.3)%, respectively. The income tax expense and effective tax rate for the three months ended June 30, 2018 was significantly impacted by the
U.S. Tax Cuts and Jobs Act of 2017 (the “2017 Tax Act
”) including administrative guidance issued by the Internal Revenue Service on April 2, 2018. This guidance resulted in a change to the calculation of the mandatory one-time tax on accumulated earnings of foreign subsidiaries in 2017 and a tax benefit of $0.5 million was recorded in tax expense with a corresponding reduction in the effective tax rate of 13.1%.
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. The final determination of the impact of the 2017 Tax Act and the remeasurement of our deferred assets and liabilities will be completed as additional information becomes available, but no later than one year from the enactment of the 2017 Tax Act in accordance with SAB 118. 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 June 30, 2018. We will continue to refine our provisional estimates for our computations under the GILTI and FDII rules as we gather additional information.
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 tax items, our tax rate has been and will continue to be volatile.
Six Months Ended June 30, 2018 compared to Six Months Ended June 30, 2017
Revenues
Revenues were $114.1 million for the six months ended June 30, 2018 as compared to $95.5 million for the six months ended June 30, 2017. This increase was primarily attributable to an increase in the volume of sales of our fracturing systems and well construction products and services due to higher customer drilling and well completion activity in North America as well as the contributions from Repeat Precision and tracer diagnostics services, both of which were added through acquisitions completed during 2017. Product sales for the six months ended June 30, 2018 were $77.9 million as compared to $75.0 million for the six months ended June 30, 2017. Our service revenue was $36.2 million for the six months ended June 30, 2018 as compared to $20.5 million for the six months ended June 30, 2017.
Cost of sales
Cost of sales was $53.5 million, or 46.9% of revenues, for the six months ended June 30, 2018 as compared to $48.2 million, or 50.5% of revenues, for the six months ended June 30, 2017. The increase in cost of sales was primarily a result of higher product sales in addition to the inclusion of Repeat Precision and tracer diagnostics services. Cost of sales was a lower percentage of revenues due to the relative increase in services revenue and higher sales volumes for well construction products and at Repeat Precision, which enabled better utilization of fixed costs.
Cost of product sales was $37.3 million, or 47.9% of product sales revenue, and cost of services was $16.2 million, or 44.7% of service revenue, for the
six months
ended June 30, 2018. For the
six months
ended June 30, 2017, cost of product sales was $40.4 million, or 54.0% of product sales revenue, and cost of services was $7.8 million, or 38.0% of service revenue.
Selling, general and administrative expenses
Selling, general and administrative expenses were $43.2 million for the six months ended June 30, 2018 as compared to $28.9 million for the six months ended June 30, 2017. The increase was the direct result of headcount additions in substantially all functional areas, six months of operations for tracer diagnostics services and an increase in share-based compensation related to
the issuance of restricted stock units and performance stock unit awards as well as amendments to certain stock options in connection with our IPO during the second quarter of 2017
. The increases were partially offset by significant non-capitalizable additional expenses incurred related to our IPO of $2.2 million and acquisition costs of $0.7 million incurred during the six months ended June 30, 2017.
Depreciation
Depreciation was $2.3 million for the six months ended June 30, 2018 as compared to $1.2 million for the six months ended June 30, 2017. The increase is attributable to a higher level of property and equipment, primarily related to our acquisitions.
Amortization
Amortization was $6.6 million for the six months ended June 30, 2018 as compared to $12.0 million for the six months ended June 30, 2017. The decrease in amortization was related to intangible assets that became fully amortized during the fourth quarter of 2017. The decrease was partially offset by an increase in amortizable intangible assets related to our acquisitions.
Change in fair value of contingent consideration
Change in fair value of contingent consideration was $(1.1) million for the six months ended June 30, 2018 compared to $0.8 million for the six months ended June 30, 2017 due to the
change in the fair value of the earn-outs associated with our acquisitions.
Interest expense, net
Interest expense, net was $1.1 million for the six months ended June 30, 2018 as compared to $3.5 million for the six months ended June 30, 2017. The decrease in interest expense, net was primarily a result of prepaying our prior term loan in full in May 2017 by utilizing a portion of the proceeds from our IPO. The decrease was partially offset by higher interest expense due to borrowing $20.0 million under our Senior Secured Credit Facility in August 2017.
Other income, net
Other income, net was $40 thousand for the six months ended June 30, 2018 as compared to $1.0 million for the six months ended June 30, 2017. Other income, net was lower primarily due to the receipt of $0.9 million from an arbitration case that was decided in our favor in February 2017.
Foreign currency exchange gain
Foreign currency exchange gain was $0.3 million for the six months ended June 30, 2018 as compared to a gain of $1.0 million for the six months ended June 30, 2017. The change was primarily due to the impact of the retirement of our foreign currency denominated debt and movement in the foreign currency exchange rates between the periods.
Income tax (benefit) expense
Income tax (benefit) expense was
$(0.1)
million for the six months ended June 30, 2018 as compared to $1.2 million for the six months ended June 30, 2017. For the six months ended June 30, 2018 and 2017, our effective income tax rates were (0.8)% and 43.7%, respectively. The income tax expense and effective tax rate for the six months ended June 30, 2018 was significantly impacted by the
U.S. Tax Cuts and Jobs Act of 2017 (the “2017 Tax Act
”) including administrative guidance issued by the Internal Revenue Service on April 2, 2018. This guidance resulted in a change to the calculation of the mandatory one-time tax on accumulated earnings of foreign subsidiaries in 2017 and a tax benefit of $2.6 million was recorded in tax expense with a corresponding reduction in the effective tax rate of 29.1%. Additionally, the effective tax rate for June 30, 2018 included a tax benefit of $0.3 million for the tax effect of exercised stock option awards.
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. The final determination of the impact of the 2017 Tax Act and the remeasurement of our deferred assets and liabilities will be completed as additional information becomes available, but no later than one year from the enactment of the 2017 Tax Act in accordance with SAB 118. 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 six months ended June 30, 2018. We will continue to refine our provisional estimates for our computations under the GILTI and FDII rules as we gather additional information.
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 tax 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 June 30, 2018, we had cash and cash equivalents of $33.5 million and availability under the Senior Secured Credit Facility of $55.0 million. Our total indebtedness was $25.0 million as of June 30, 2018.
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 six months ended June 30, 2018 and 2017 were $3.8 million and $3.9 million, respectively. We plan to incur approximately $15 million to $18 million in capital expenditures during 2018, which includes capital expenditures related to a new enterprise resource planning system, the establishment of a laboratory in Canada supporting our tracer diagnostics business, additional machining capacity at Repeat Precision and the remainder of the estimated spending for our research and development facility described below. We are investing in our owned facility in Canada to create a research and development facility for product development as well as to further demonstrate the capabilities and benefits of our products to our customers. We estimate total spending for the project to be approximately $11 million CAD ($8.4 million at June 30, 2018), which started in 2017 and which we expect will be completed in late 2018 or early 2019.
We believe our cash on hand, cash flows from operations and potential borrowings under our Senior Secured Credit Facility will be sufficient to fund our capital expenditure and liquidity requirements for the next twelve months.
We anticipate that to the extent that we require additional liquidity, it will be funded through the incurrence of additional indebtedness, the proceeds of equity issuances, or a combination thereof. We cannot assure you that we will be able to obtain this additional liquidity on reasonable terms, or at all. Our liquidity and our ability to meet our obligations and fund our capital requirements are also dependent on our future financial performance, which is subject to general economic, financial and other factors that are beyond our control. Accordingly, we cannot assure you that our business will generate sufficient cash flow from operations or that funds will be available from additional indebtedness, the capital markets or otherwise to meet our liquidity needs. If we decide to pursue one or more significant acquisitions, we may incur additional debt or sell additional equity to finance such acquisitions, which could result in additional expenses or dilution.
Cash Flows
The following table provides a summary of cash flows from operating, investing and financing activities for the periods presented (in thousands):
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Six Months Ended
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June 30,
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2018
|
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2017
|
Net cash provided by operating activities
|
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$
|
7,495
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$
|
7,040
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Net cash used in investing activities
|
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|
(3,550)
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(8,732)
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Net cash (used in) provided by financing activities
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(2,909)
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|
63,362
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Effect of exchange rate changes on cash and cash equivalents
|
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(1,368)
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46
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Net change in cash and cash equivalents
|
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$
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(332)
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$
|
61,716
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Operating Activities
Net cash provided by operating activities was $7.5 million and $7.0 million for the six months ended June 30, 2018 and 2017, respectively.
The increase in 2018 was primarily related to higher net income as a result of increased business activity and changes in working capital including accounts receivable and inventories. The increase was partially offset by changes to income tax receivable/payable.
Investing Activities
Net cash used in investing activities was $3.6 million and $8.7 million for the six months ended June 30, 2018 and 2017, respectively.
The decrease in cash used in investing activities during the six months ended June 30, 2018 as compared to the six months ended June 30, 2017 was primarily related to the $6.0 million funding of our 50% interest in Repeat Precision in 2017.
See “Note 3. Acquisitions”
in
our unaudited condensed consolidated financial statements.
The decrease was partially offset by a $1.0 million note receivable repayment during the six months ended June 30, 2017.
Financing Activities
The net cash used in financing activities for the six months ended June 30, 2018 was $2.9 million as compared to net cash provided by financing activities of $63.4 million. The change between net cash used in financing activities for the six months ended June 30, 2018 and net cash provided by financing activities for the six months ended June 30, 2017 was primarily related to net proceeds from the completion of our IPO on May 3, 2017 of $148.9 million, after deducting underwriting discounts and commissions and other offering expenses, which was partially offset by the $89.1 million repayment of the prior term loan under our prior senior secured credit facility during the second quarter of 2017.
Financing Arrangement
On May 4, 2017, we entered into an Amended and Restated Credit Agreement (the “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 U.S. Facility (as defined below) and Wells Fargo Bank, National Association, Canadian Branch as administrative agent in respect of the Canadian Facility (as defined below) (the senior secured revolving credit facilities provided thereunder, the “Senior Secured Credit Facility”).
The Credit Agreement amended and restated the prior credit agreement in its entirety. The Senior Secured Credit Facility will mature on May 4, 2020.
The Senior Secured Credit Facility originally consisted of a (i) senior secured revolving credit facility in an aggregate principal amount of $25.0 million made available to the U.S. Borrower (the “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 “Canadian Facility”).
We entered into Amendment No. 1 to the Credit Agreement on August 31, 2017, which increased the loan commitment available to the U.S. Borrower to $50.0 million from $25.0 million under the U.S. Facility. The loan commitment available under the Canadian Facility remained at $25.0 million.
On February 16, 2018, we entered into Amendment No. 2 to the Credit Agreement, which amended certain negative covenants contained in the Credit Agreement.
At June 30, 2018, we had $20.0 million in outstanding indebtedness under the U.S. Facility and no outstanding indebtedness under the Canadian Facility.
Borrowings under the U.S. Facility may be made in U.S. dollars, Canadian dollars or Euros and bear interest at a rate equal to the Adjusted Base Rate or Eurocurrency Rate (each as defined in the Credit Agreement), in each case, plus an applicable interest margin
as set forth in the Credit Agreement. Borrowings under the 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 Credit Agreement), in each case, plus an applicable interest margin as set forth in the Credit Agreement.
The Adjusted Base Rate, Canadian (U.S.) Base Rate and Canadian (Cdn) Base Rate applicable margin will be between 2.25% and 3.00% and Eurocurrency Rate applicable margin will be between 3.25% and 4.00%, in each case, depending on the Company’s leverage ratio. The applicable interest rate at June 30, 2018 was 6.25%.
The obligations of the U.S. Borrower under the 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 Canadian Facility are guaranteed by the Parent Guarantors, the U.S. Borrower and each of the 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 subsidiary guarantors, if any, in each case, subject to certain exceptions and permitted liens.
The Credit Agreement contains financial covenants that require (i) commencing with the fiscal quarter ending June 30, 2017, compliance with a leverage ratio test set at (A) 3.00 to 1.00 as of the last day of each fiscal quarter ending prior to March 31, 2018 and (B) 2.50 to 1.00 as of the last day of each fiscal quarter ending on or after March 31, 2018, (ii) commencing with the fiscal quarter ending June 30, 2017, compliance with an interest coverage ratio test set at 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 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 set at 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 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 set at 1.00 to 1.00.
As of June 30, 2018, we were in compliance with these financial covenants.
The 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 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 U.S. Facility and the 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
U.S. Facility and the 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 U.S. Facility and the Canadian Facility
, the lenders thereunder will have the right to proceed against the collateral granted to them to secure such facility.
Contractual Obligations
Except for the $2.6 million reduction of
income tax payable related to the 2017 Tax Act as discussed
in “Note 12. Income Taxes” in our unaudited condensed consolidated financial statements, there have been no material changes in our contractual obligations and commitments disclosed in the
Annual Report for the year ended December 31, 2017.
Off-Balance Sheet Arrangements
We have no off-balance sheet financing arrangements with the exception of operating leases.
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 revenue recognition policies in conjunction with our adoption of ASU 2014-09 and its related amendments (collectively known as “ASC 606”) as further described in “Note 2. Revenue
s
” in our unaudited condensed consolidated financial statements.
T
here are no other material changes to our critical accounting policies
from those included in the Annual Report for the year ended December 31, 2017.
Recently Issued Accounting Pronouncements
See “Note 1. Basis of Presentation”
to our unaudited condensed consolidated financial statements
for discussion of the accounting pronouncements we recently adopted and the accounting pronouncements recently issued by the Financial Accounting Standards Board.
Jumpstart Our Business Act of 2012
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. An emerging growth company may take advantage of specified reduced reporting and other burdens that are otherwise applicable generally to public companies.
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 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:
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declines in the level of oil and natural gas exploration and production activity within Canada and the United States;
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oil and natural gas price fluctuations;
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loss of significant customers;
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inability to successfully implement our strategy of increasing sales of products and services into the United States;
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significant competition for our products and services;
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our inability to successfully develop and implement new technologies, products and services;
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our inability to protect and maintain critical intellectual property assets;
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currency exchange rate fluctuations;
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·
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impact of severe weather conditions;
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·
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restrictions on the availability of our customers to obtain water essential to the drilling and hydraulic fracturing processes;
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·
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our failure to identify and consummate potential acquisitions;
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·
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our inability to integrate or realize the expected benefits from acquisitions;
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our inability to meet regulatory requirements for use of certain chemicals by our tracer diagnostics business;
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·
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our inability to accurately predict customer demand;
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·
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losses and liabilities from uninsured or underinsured drilling and operating activities;
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changes in legislation or regulation governing the oil and natural gas industry, including restrictions on emissions of greenhouse gases;
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changes in trade policy, including the impact of additional tariffs;
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failure to comply with or changes to federal, state and local and non-U.S. laws and other regulations, including environmental regulations a
nd the 2017 Tax Act;
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loss of our information and computer systems;
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system interruptions or failures, including cyber-security breaches, identity theft or other disruptions that could compromise our information;
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our failure to establish and maintain effective internal control over financial reporting;
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complications with the design and implementation of our new enterprise resource planning system;
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our success in attracting and retaining qualified employees and key personnel; and
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our inability to satisfy technical requirements and other specifications under contracts and contract tenders.
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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.