10-K 1 klxe-20200131x10k.htm 10-K klxe_Current Folio_10K

                                                                                                                                                                                                    

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549


FORM 10-K


 

 

(Mark One)

 

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934

For the fiscal year ended: January 31, 2020

or

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934

For the transition period from              to             .

Commission File Number: 001‑38609

KLX ENERGY SERVICES HOLDINGS, INC.

(Exact name of registrant as specified in its charter)


 

 

 

 

Delaware
(State of incorporation or organization)

36-4904146
(I.R.S. Employer Identification No.)

 

 

1300 Corporate Center Way Wellington, Florida

33414

(Address of principal executive offices)

(Zip Code)

(561) 383‑5100

(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:

 

 

 

Title of Each Class

Trading Symbol(s)

Name of Each Exchange on Which Registered

Common Stock, $0.01 Par Value

KLXE

The Nasdaq Global Select Market

Securities registered pursuant to Section 12(g) of the Act: None.

Indicate by check mark if the registrant is a well‑known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☐  No ☒

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐  No ☒

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days: Yes ☒  No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S‑T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒  No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non‑accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b‑2 of the Exchange Act.

 

 

 

 

 

 

 

 

 

Large accelerated filer ☐

Accelerated filer ☒

Non‑accelerated filer ☐

Smaller reporting company ☐

Emerging growth company ☒

 

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.  ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b‑2 of the Exchange Act). Yes ☐  No ☒

As of July 31, 2019, the aggregate market value of the registrant’s voting stock held by non‑affiliates was approximately $331.4 million. Shares of common stock held by executive officers and directors have been excluded since such persons may be deemed affiliates. This determination of affiliate status is not a determination for any other purpose. The number of shares of the registrant’s common stock, $0.01 par value, outstanding as of March 20, 2020 was 24,742,626 shares.

 

DOCUMENTS INCORPORATED BY REFERENCE

Certain sections of the registrant’s Proxy Statement to be filed with the Commission in connection with the 2020 Annual Meeting of Stockholders or Annual Report on Form 10‑K/A, to be filed with the Securities and Exchange Commission within 120 days after the close of the registrant’s fiscal year, are incorporated by reference in Part III of this Form 10‑K. With the exception of those sections that are specifically incorporated by reference in this Annual Report on Form 10‑K, such Proxy Statement shall not be deemed filed as part of this Report or incorporated by reference herein.

 

 

 

TABLE OF CONTENTS

 

 

 

 

 

Page

 

PART I

 

ITEM 1. 

Business

4

ITEM 1A. 

Risk Factors

16

ITEM 1B. 

Unresolved Staff Comments

37

ITEM 2. 

Properties

38

ITEM 3. 

Legal Proceedings

38

ITEM 4. 

Mine Safety Disclosures

39

 

PART II

 

ITEM 5. 

Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

40

ITEM 6. 

Selected Financial Data

41

ITEM 7. 

Management’s Discussion and Analysis of Financial Condition and Results of Operations

44

ITEM 7A. 

Quantitative and Qualitative Disclosures About Market Risk

56

ITEM 8. 

Financial Statements and Supplementary Data

57

ITEM 9. 

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

57

ITEM 9A. 

Controls and Procedures

57

ITEM 9B. 

Other Information

59

 

PART III

 

ITEM 10. 

Directors, Executive Officers and Corporate Governance

59

ITEM 11. 

Executive Compensation

64

ITEM 12. 

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

64

ITEM 13. 

Certain Relationships and Related Party Transactions, and Director Independence

64

ITEM 14. 

Principal Accountant Fees and Services

64

 

PART IV

 

ITEM 15. 

Exhibits and Financial Statement Schedules

65

 

Signatures

68

 

Index to Consolidated Financial Statements and Schedule

F‑1

 

 

1

CAUTIONARY STATEMENT REGARDING FORWARD‑LOOKING STATEMENTS

The Private Securities Litigation Reform Act of 1995 provides a “safe harbor” for forward‑looking statements to encourage companies to provide prospective information to investors. This Annual Report on Form 10‑K (this “Form 10‑K”) includes forward‑looking statements that reflect our current expectations and projections about our future results, performance and prospects. Forward‑looking statements include all statements that are not historical in nature or are not current facts. We have tried to identify these forward‑looking statements by using forward‑looking words including “believe,” “expect,” “plan,” “intend,” “anticipate,” “estimate,” “predict,” “potential,” “continue,” “may,” “might,” “should,” “could,” “will” or the negative of these terms or similar expressions.

These forward‑looking statements are subject to a number of risks, uncertainties, assumptions and other factors that could cause our actual results, performance and prospects to differ materially from those expressed in, or implied by, these forward‑looking statements. These factors include the risks, uncertainties, assumptions and other factors discussed under the headings “Item 1A. Risk Factors,” as well as “Item 1. Business”, “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and elsewhere in this Form 10‑K, including the following factors:

·

regulation of and dependence upon the energy industry;

·

the cyclical nature of the energy industry;

·

market prices for fuel, oil and natural gas;

·

competitive conditions;

·

legislative or regulatory changes and potential liability under federal and state laws and regulations;

·

decreases in the rate at which oil or natural gas reserves are discovered or developed;

·

the impact of technological advances on the demand for our products and services;

·

delays of customers obtaining permits for their operations;

·

hazards and operational risks that may not be fully covered by insurance;

·

the write-off of a significant portion of intangible assets;

·

the need to obtain additional capital or financing, and the availability and/or cost of obtaining such capital or financing;

·

limitations that our organizational documents, debt instruments and U.S. federal income tax requirements may have on our financial flexibility, our ability to engage in strategic transactions or our ability to declare and pay cash dividends on our common stock;

·

our credit profile;

·

changes in supply and demand of equipment;

·

oilfield anti-indemnity provisions;

·

severe weather;

·

global or national health pandemics, epidemics or concerns, such as the recent COVID-19 outbreaks;

·

reliance on information technology resources and the inability to implement new technology;

·

increased labor costs or the unavailability of skilled workers;

·

the inability to successfully consummate acquisitions or inability to manage future growth; and

·

the inability to achieve some or all of the benefits of the spin-off.

 

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In light of these risks and uncertainties, you are cautioned not to put undue reliance on any forward‑looking statements in this Form 10‑K. These statements should be considered only after carefully reading this entire Form 10‑K. Except as required under the federal securities laws and rules and regulations of the SEC, we undertake no obligation to publicly update or revise any forward‑looking statements, whether as a result of new information, future events or otherwise. Additional risks that we may currently deem immaterial or that are not presently known to us could also cause the forward‑looking events discussed in this Form 10‑K not to occur.

3

PART I

ITEM 1.  BUSINESS

Except as otherwise indicated or unless the context otherwise requires, “KLX Energy Services,” “we,” “us” and “our” refer to KLX Energy Services Holdings, Inc. and its consolidated subsidiaries after giving effect to the spin-off, and “KLX” refers to KLX Inc., its predecessors and its consolidated subsidiaries, other than, for all periods following the spin-off, KLX Energy Services Holdings, Inc. and its consolidated subsidiaries. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Overview – The Spin-Off.” Our fiscal year ends on January 31, as a result, the years ended January 31, 2020, 2019, 2018, 2017 and 2016 are referred to as “Fiscal 2019, Fiscal 2018, Fiscal 2017, Fiscal 2016 and Fiscal 2015,” respectively.

Our Company

We are a leading provider of completion, intervention and production services and products (our “product service lines” or “PSLs”) to the major onshore oil and gas producing regions of the United States. We offer a range of differentiated, complementary technical services and related tools and equipment in challenging environments that provide “mission critical” solutions for our customers throughout the life cycle of the well.

We serve many of the leading companies engaged in the exploration and development of North American onshore conventional and unconventional oil and natural gas reserves. Our customers are primarily independent major oil and gas companies. We actively support these customer operations from over 35 principal service facilities located in the key major shale basins. We operate in three segments on a geographic basis, including the Southwest Region (the Permian Basin and the Eagle Ford), the Rocky Mountains Region (the Bakken, Williston, DJ, Uinta, Powder River, Piceance and Niobrara basins) and the Northeast/Mid-Con Region (the Marcellus and Utica as well as the Mid-Continent STACK and SCOOP and Haynesville). Our revenues, operating profits and identifiable assets are primarily attributable to these three reportable geographic segments. However, while we manage our business based upon these regional groupings, our assets and our technical personnel are deployed on a dynamic basis across all of our service facilities to optimize utilization and profitability.

We work with our customers to provide engineered solutions across the entire lifecycle of the well, by streamlining operations, reducing non-productive time and developing cost effective solutions and customized tools for our customers’ most challenging service needs, which include technically complex unconventional wells requiring extended reach horizontal laterals with greater completion intensity per well. We believe long-term revenue growth opportunities will continue to be driven by increases in the number of new customers served and the breadth of services we offer to existing and prospective customers.

We offer a variety of targeted services that are differentiated by the technical competence and experience of our field service engineers and their deployment of a broad portfolio of specialized tools and equipment. Our innovative and adaptive approach to proprietary tool design has been employed by our in-house research and development (“R&D”) organization and, in selected instances, by our technology partners to develop tools covered by 20 patents and 18 U.S. and foreign pending patent applications. Our technology partners include manufacturing and engineering companies that produce tools, which we design and utilize in our service offerings.

We utilize contract manufacturers to produce our products, which, in many cases, our engineers have developed from input and requests from our customers and customer-facing managers, thereby maintaining the integrity of our intellectual property while avoiding manufacturing startup and maintenance costs. We have found that doing so leverages our technical strengths as well as those of our technology partners. These services and related products, or PSLs, are modest in cost to the customer relative to other well construction expenditures but have a high cost of failure and are, therefore, “mission critical” to our customers’ outcomes. We believe our customers have come to depend on our decades of combined field experience to execute on some of the most challenging problems they face. We believe we are well positioned as a company to service customers when they are drilling and completing complex wells and remediating older legacy wells.

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KLX Energy Services was initially formed from the combination and integration of seven private oilfield service companies acquired over the 2013 through 2014 time period. Each of the acquired businesses was regional in nature and brought one or two specific service capabilities to KLX Energy Services. Once the acquisitions were completed, we undertook a comprehensive integration of these businesses, to align our services, our people and our assets across all the geographic regions where we maintain a presence. We established a matrix management organizational structure, where each regional manager has the resources to provide a complete suite of services, supported by technical experts in our primary service categories. In November 2018, we expanded our completion and intervention service offerings through the acquisition of Motley Services, LLC (“Motley”), a premier provider of large diameter coiled tubing services, further enhancing our completion tools business. We successfully completed the integration of the Motley business during Fiscal 2018. On March 15, 2019, the Company acquired Tecton Energy Services (“Tecton”), a leading provider of flowback, drill-out and production testing services, operating primarily in the greater Rocky Mountains. On March 19, 2019, the Company acquired Red Bone Services LLC (“Red Bone”), a premier provider of oilfield services primarily in the Mid-Continent, providing fishing, non-frac high pressure pumping, thru-tubing and certain other services. We successfully completed the integration of the Red Bone business during Fiscal 2019. We have endeavored to create a “next generation” oilfield services company in terms of management controls, processes and operating metrics and have driven these processes down through the operating management structure in every region, which we believe differentiates us from many of our competitors. This allows us to offer our customers in all of our geographic regions discrete, comprehensive and differentiated services that leverage both the technical expertise of our skilled engineers and our in-house R&D team.

Industry Overview

The oil and gas industry has historically been both cyclical and seasonal. Activity levels are driven primarily by drilling rig counts, technological advances, well completions and workover activity, the geological characteristics of the producing wells and their effect on the services required to commence and maintain production levels and our customers’ capital and operating budgets. All of these indicators are driven by commodity prices, which are affected by both domestic and global supply and demand factors. In particular, while U.S. natural gas prices are correlated with global oil price movements, they are also affected by local weather, transportation and consumption patterns.

Global supply and demand factors will continue to result in commodity price volatility, with substantially lower demand and prices for oilfield services in 2020. The long-term positive attributes of the onshore North American oil and gas industry are the following:

Increase in Onshore Unconventional Resources.  The development of new recovery technologies has been leading to a shift toward the drilling and development of onshore unconventional oil and natural gas resources, which requires more wells to be drilled and active maintenance to sustain production and maximize recoveries. We believe the increased production requirements of these unconventional resources, in the long-term, will support increasing service activity over time when the industry eventually rebalances its allocation of assets in the future to meet demand. However, with oil and gas prices at historic lows and the ongoing effects of the global COVID-19 outbreaks likely to result in a global recession, in the near-term, we expect fewer oil and gas wells to be drilled, fewer wells to be completed and a significant decrease in demand and prices for our services.

Numerous Technology Breakthroughs.  We believe technologically driven breakthroughs, including (i) continued drilling activity supported by unconventional resources, (ii) the expanding use of horizontal drilling techniques and (iii) longer lateral lengths and the increasing number of stages per well, have created a long-term trend of growing demand for top-level services and products to support these advanced drilling and completion activities, many of which take place in remote areas with harsh environments.

Increasing Complexity of Technology.  The increasing complexity of technology used in the oil and natural gas exploration and development process requires additional technicians on location during the drilling and completion operations. In particular, the increasing trend of pursuing horizontal and directional wells as opposed to vertical wells requires additional expertise on location.

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Large U.S. Oil and Gas Reserves.  The United States is committed to a long-term goal of energy independence. Currently identified recoverable reserves of 344 billion barrels of shale oil and 2,829 trillion cubic feet of shale gas are contained within the United States, according to the EIA’s Annual Energy Outlook 2020 Assumptions report.

Demand for Natural Gas.  We believe that natural gas will be increasingly in demand over time because of its growing popularity as a cleaner burning fuel. The ongoing shift to the use of natural gas from coal-fired power plants and increased access to residential customers from new pipeline projects are expected to support increased demand for natural gas. In addition, the recent commencement of liquefied natural gas shipments from the United States to foreign markets is also expected to be a positive factor for natural gas production over time. Currently, however, there is a global oversupply of natural gas with natural gas prices at record lows, and as a result, in the near-term, we expect there to be substantially less drilling for and consumption of natural gas during 2020.

Continued Outsourcing of Ancillary Services.  Almost all exploration and production (“E&P”) companies outsource the services required by them to drill wells and maintain production. Drilling and completion activities require numerous services and products from time to time on an “as needed” basis. Although some of the services we provide have historically been handled in-house by drilling contractors, in many instances drilling contractors will elect to outsource these services because these services are ancillary to the primary activity of drilling and completing wells and represent only a minor portion of the total well drilling cost. Drilling contractors that outsource these services look for suppliers who have the expertise to provide increasingly more complex, high-quality and reliable services on a 24/7 basis. 

Impact of Recent Industry Volatility.  In recent years, the oil and gas industry has experienced significant downturns. For example, the oilfield service industry experienced an abrupt deterioration in demand during the second half of 2019, which led to a sharp decline in U.S. land rig count and an unprecedented decline in operating frac spreads from the second quarter through the end of 2019. These downturns placed unprecedented pressure on both our customers and competitors.

Oil prices declined sharply in March 2020 to levels as low as approximately $21 per barrel as a result of multiple factors affecting levels of supply and demand in global oil and gas markets, including the announcement of price reductions and production increases by OPEC members and other oil exporting nations. Oil and natural gas prices are expected to continue to be volatile as a result of the near term production increases and the ongoing COVID-19 outbreaks and as changes in oil and natural gas inventories, industry demand and global and national economic performance are reported.

Significant factors that are likely to affect commodity prices in current and future periods include, but are not limited to, the extent and duration of price reductions and increased production by OPEC members and other oil exporting nations, the effect of U.S. energy, monetary and trade policies, U.S. and global economic conditions, U.S. and global political and economic developments, including the outcome of the U.S. presidential election and resulting energy and environmental policies, the impact of the ongoing COVID-19 outbreaks and conditions in the U.S. oil and gas industry and the resulting demand and pricing for domestic land oilfield services. The reduction in oil prices and the ongoing effects of the global COVID-19 outbreaks will likely result in a global recession, with the possibility of numerous bankruptcies of E&P companies and oilfield services companies during 2020 and a significant decline in demand and prices for oilfield services during 2020. We have taken, and are continuing to take, steps to reduce costs, including reductions in capital expenditures, as well as other workforce rightsizing and ongoing cost initiatives. 

Products and Services

We offer high value-added services and related tools and equipment supporting the completion, intervention and production activities of our customers in each of our geographic reporting segments. The principal services we offer to support our customers throughout the lifecycle of the well include completions, well intervention and production services and products.

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Completions: Our completions activities are focused on services that help our customers drill, complete and stimulate extended reach horizontal laterals and more technical wellbores (the physical conduit from surface into the hydrocarbon reservoir). We are highly experienced in safely servicing deep, high-pressure, high-temperature wells in some of the most active onshore basins in the United States and provide premium perforating services for both wireline and tubing-conveyed applications. We believe we offer best-in-class service execution at the wellsite and innovative downhole technologies, positioning us to benefit from our ability to service the most technically complex wells where the potential for increased operating leverage is high due to the large number of stages per well in addition to customer focus on execution rather than price. We provide plug-and-perf wireline operations, wireline logging services, frac stack services and equipment, accommodation services, coiled tubing, flowback and testing services, high pressure blow out prevention (“BOP”) equipment and downhole completions tools.

Our completions activities include a wide range of services:

·

pressure control services;

·

frac valve and flowback and testing services;

·

wireline services (including pump down, logging, pipe recovery and slick line);

·

well testing and nipple-up services;

·

downhole completion tools, including:

o

IPA toe sleeves;

o

liner hangers;

o

KLXE cementing bypass subs;

o

composite plugs;

o

proprietary dissolvable plugs;

·

downhole extended-reach technology;

·

HAVOK™ motor bearing assembly; and

·

coiled tubing services.

 

We believe our HAVOK™ motor bearing system together with an extended reach tool utilized under a cooperative marketing agreement complements our large diameter coiled tubing product service line in servicing extreme extended reach laterals. The extended reach tool reduces the friction drag and extends the lateral reach of the tubing by delaying the onset of helical buckling and lockup. We have successfully run this extended reach tool on numerous wells above our own proprietary HAVOK downhole motor, which boasts the industry’s only all-polycrystalline diamond compact bearing design. These tools have proven to be a formidable combination, delivering superior results for our customers. Further, we are successfully leveraging our coiled tubing assets to pull through our non-frac high pressure pumping, wireline, thru-tubing and certain other services.

 

We partnered with an engineering firm to co-develop a magnesium alloy based line of dissolvable plugs. Our proprietary dissolvable plugs deliver all the benefits of a traditional frac plug, but without the need for bottom hole intervention for removal. Our dissolvable plugs have been deployed in over 600 wells for over 60 customers with superior results compared to competitive products. Our plugs dissolve quickly and reliably, resulting in faster time to production, are effective in a wide range of operating temperatures and salinity, including temperatures ranging from 80 to 275 degrees Fahrenheit, and do not require mill out, thus saving time and cost.

 

The KLXE flotation collar is the only casing flotation system on the market that introduces zero debris into the wellbore and requires no specialized plug sets to operate. It is used in extended, horizontal applications to reduce friction forces and better allow the efficient construction of extended laterals. The KLXE flotation collar is designed to be simple, consistent and highly reliable in extended, horizontal applications.

 

A portion of our completion services is delivered by our fleet of wireline trucks and associated tools which are configured to run pump down or plug-and-perf operations. Our R&D organization also enables our operations to support our customers with cutting edge pump down operations that include greaseless wireline, addressable gun systems and addressable release tools, to provide our customers with the highest quality pump down services. We also maintain a full line of radial cement bond tools, compensated neutron porosity tools and casing evaluation tools to provide well

7

evaluation services to our clients. We also utilize greaseless line and quiet truck wireline technology to meet the environmental concerns of our customers in markets that require this technology.

 

While our company does not provide hydraulic fracturing (“frac”) services, we do provide equipment and services to support our customers’ hydraulic fracturing operations, including a number of proprietary tools that deliver both increased efficiency and safety. We offer a full line of valves and corresponding services to assist clients with their pressure control needs during fracturing operations. These valves are assembled in predetermined configurations based on customer preference and installed on the wellhead to control flow and pressure during fracturing operations. We own a large, young fleet of valves serving the North American onshore oil and gas market. We have enhanced our frac valve fleet line through the internal development of next generation technology, including our proprietary, patent pending frac relief valve (“FRV”). Introduced in 2016, the FRV was built and designed to replace older “pop-off” systems. When tied into a frac core (pumps), the FRV gives customers a safer and more reliable method for relieving surface pressure in the event of an unforeseen overpressure event. By doing this, we believe we minimize operational risk, as well as greatly reduce health, safety and environmental (“HSE”) concerns that are associated with fracturing operations.

 

Additional technologies that we currently deploy on behalf of our customers include our (i) patent pending floatation collar, which assists customers in getting completion (casing) to the bottom of extended reach wells when friction prevents getting casing to depth, (ii) proprietary IPA toe sleeve, which allows customers a consistent and reliable frac initiation sleeve at the toe of the completion, (iii) composite frac plug, a flow control device that is set in the wellbore at given intervals to divert fluid into the formation, and (iv) dissolvable plugs.

 

Wellbore Interventions:  Our intervention services consist of best-in-class technicians and equipment that are focused on providing customers engineered solutions to downhole complications. Intervention involves the application of specialized tools and procedures to retrieve lost equipment and remove other obstructions that either interfere with the completion of the well or are causing diminished production. The principal services we provide to remediate these complications include fishing, thru-tubing and pipe recovery. Given the unique geology and operating characteristics of each well, no two complications are the same, yet each complication our customers experience results in substantial

disruption to their well operation and economics. As a result, resolution is “mission critical” to our customers and superior outcomes can support premium pricing. Those outcomes rely principally on the skill and experience of the technicians dedicated to resolving the issues and the availability of exactly the right tools for every eventuality. We believe we have one of the leading teams of intervention specialists in the industry, supported by a comprehensive portfolio of intervention tools and equipment. Each of our geographic regions is fully staffed with top technicians and fully equipped with a comprehensive range and quantity of equipment given the wellbore profiles for the region.

 

In November 2018, we acquired Motley, which is a premier provider of large diameter coiled tubing. During Fiscal 2019, we rolled out our coiled tubing product line to each of our business segments. As of January 31, 2020, we had a fleet of 12 large diameter coiled tubing spreads across our geographical regions. Over time, when the industry recovers, we believe that our investments in large diameter coil tubing spreads will allow us to increase our share of spend as the large diameter coil tubing pulls through asset light services such as flowback and testing services, thru-tubing and pressure control services, while leveraging our recently enhanced cost structure.

 

We support our intervention group with a portfolio of tools consisting of both patented and proprietary technologies. Recent innovations currently deployed in the field include our: (i) DXD Venturi Tool; (ii) HAVOK PDC Bearing Section; (iii) Hydraulic By-Pass Tool; and (iv) Drill Mate (Mechanical By-Pass Valve). These tools were designed to improve upon conventional technology used by our competitors:

 

DXD Venturi Tool—The patent pending DXD (Debris Extraction Device) is an internally developed downhole tool that assists customers in removing unwanted debris from the wellbore. Utilizing fluid dynamics, the tool consists of a jet section that accelerates fluid across a nozzle. This increase in fluid velocity creates a pressure drop inside the tool, which draws fluid through an inlet. As the fluid is drawn into the system through the inlet, it picks up unwanted debris in the fluid flow, which is then caught in a series of chambers installed below the tool. The chambers then carry the debris out of the hole when the system is brought back to surface.

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HAVOK PDC Bearing Section—The patented HAVOK PDC is one of the most robust bearing packs on the market. With a total of five parts, this bearing pack has greatly reduced the operating cost of our thru-tubing motors and provides us with a significant differentiator in the thru-tubing market. We began deploying the bearing pack in early 2017 and have experienced excellent results with the tool.

 

Hydraulic By-Pass Tool—The patented hydraulic by-pass tool allows us to run our conventional motor assemblies and achieve substantially higher circulation rates without reducing the expected life of our conventional power section. The additional fluid being pumped and by-passed optimizes the downhole hydraulics for the operation and assists with proper debris removal.

 

Drill Mate (Mechanical By-Pass Valve)—The patented Drill Mate is a downhole tool that was developed to give customers a way to mechanically by-pass fluid during drill out or clean out operations. The tool is a two-piece system that opens and closes based upon the amount of weight being set on the mill or bit. During bottom milling with the tool, the tool is in the closed position, putting 100% of the flow through the motor BHA. As weight is removed from the mill or bit either by milling through the obstruction or picking up off bottom, the tool strokes open, thereby exposing by-pass ports that divert fluid through them. At this point, a customer can increase the amount of fluid being pumped through the BHA to assist in debris removal. This increase in fluid rate does not affect the life of the motor as the additional fluid is by-passed through the Drill Mate tool.

 

Production Solutions:  We also provide services to enhance and maintain oil and gas production throughout the productive lives of our customers’ wells. Our production services include maintenance related intervention services as well as the provision of specifically required products and equipment. As with our completion and intervention service offerings, we have developed a portfolio of proprietary tools that we believe differentiates our production solutions service offering. The principal services and equipment we provide across the production lifecycle of the well include (i) production BOPs, (ii) the provision of mechanical wireline services, (iii) slick line services, (iv) hydro-testing, (v) premium tubulars and (vi) other specialized production tools.

 

We believe our proprietary production tool portfolio creates a distinct competitive advantage for us in selling all of our production services. Key downhole production tools we have developed and that have been deployed with strong customer adoption include:

 

Punch Ram Tool—The punch ram tool gives customers the ability to safely and repeatedly release trapped pressure inside production tubulars during pulling operations. The alternative is to “hot-tap” the tubing, which is a high-risk operation that most operators are not willing to employ.

 

Frac Protect Rod Hang Off Tool—This tool is developed to give customers the ability to “hang off” a rod string rather than tripping it out of the hole and laying it down. The associated costs of tripping rods out of the hole coupled with the damage of laying them down and picking the string back up make this tool an excellent alternative option for customers. The hang off tool allows an operator to easily hang the rod string in the wellhead and still gives them the ability to tie into the tubing if need be to monitor pressure or pump fluid.

 

Customers and Marketing

Substantially all of our customers are engaged in the energy industry. Most of our sales are to regional, independent and major oil and gas companies, and these sales have resulted in a diversified and geographically balanced portfolio of more than 800 customers within North America. Revenues from our five largest customers collectively represented approximately 29% of our revenues for the year ended January 31, 2020. No single customer accounted for more than 10% of our revenues in Fiscal 2019.

Our sales activities are conducted through a network of sales representatives and business development personnel, which provide coverage on a product line and geographical basis. Sales representatives work closely with local operations managers to target potential opportunities through strategic focus and planning. Customers are identified as targets based on their drilling and completion activity, geographic location and economic viability. Direction of the sales team is conducted through weekly meetings and daily communication. Our marketing activities are performed

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internally. Our strategy is based on building a strong North American brand though multiple media outlets including our website, select social media accounts, print, billboard advertisements, press releases and various industry-specific conferences, publications and lectures. We have a technical sales organization with expertise and focus within their specific service line. Our strategy is to sell our services and market our excellence through brand service quality, technology and metrics of success. We accomplish this through communication across sales and operations departments and regions to share best practices and leverage existing customer relationships.

Competition

We provide services and products and compete in a variety of distinct sub-segments with a number of competitors. Our primary competitors are regional companies, which provide a more limited range of services and equipment and often have more limited financial resources to support their operations. With respect to certain of our services, we also compete with major, multinational companies, including Schlumberger, Halliburton and Baker Hughes. Competition is based on a number of factors, including performance, safety, quality, reliability, service, price, response time and, increasingly, breadth of services and products. We maintain both regional and product/services specialist sales teams. Although sales employees tend to be based locally in regions and field locations, we have established a corporate sales team to coordinate sales and marketing efforts with our key accounts. As of January 31, 2020, we had 73 corporate and regional sales representatives with an average of over 10 years of experience. Additionally, projects are often awarded on a bid basis, which tends to create a highly competitive environment. We seek to differentiate our company from our competitors by delivering a broad range of non-frac services with the highest-quality equipment and highly competent personnel, which enables us to deliver superior execution and operating efficiency in a safe working environment. By focusing on cultivating our existing customer relationships and maintaining our high standard of customer service, technology, safety, performance and quality of crews, equipment and services, we believe we are equipped to effectively compete and succeed in a competitive market.

Suppliers and Procurement

We purchase a wide variety of materials, components and partially completed and finished products from manufacturers and suppliers for our use. We are not dependent on any single source of supply for those parts, supplies, materials or equipment. To date, we have generally been able to obtain the equipment, parts and supplies necessary to support our operations on a timely basis. While we believe that we will be able to make satisfactory alternative arrangements in the event of any interruption in the supply of these materials and/or products by one of our suppliers, we may not always be able to make alternative arrangements. In addition, certain materials for which we do not currently have long-term supply agreements could experience shortages and significant price increases in the future. As a result, we may be unable to mitigate any future supply shortages and our results of operations, prospects and financial condition could be adversely affected.

Customer Service

We are highly differentiated in each of the geographic markets that we serve with our services and associated product offerings. This is achieved by providing targeted, complementary services and related products and being responsive to our customers with both quality, as measured by the industry-standard NPT, and timely responses to any request. The key elements include:

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24-hours a day, seven days a week operations;

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recognized industry leading technicians in our principal service and product lines;

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responsiveness to our customers’ requirements for ready-to-deploy API certified equipment and a “can do” philosophy;

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technical interface with customers via product line management personnel; and

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client intimacy.

 

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Technology and Intellectual Property

 

Our engineering and technology efforts are focused on providing efficient and cost-effective solutions to maximize production for our customers across major North American onshore basins. We have dedicated resources focused on the internal development of new technology and equipment, as well as resources focused on sourcing and commercializing new technologies through strategic relationships. Our sales and earnings are influenced by our ability to successfully introduce new or improved products and services to the market.

 

Although in the aggregate our patents and licenses are important to us, we do not regard any single patent, license or strategic relationship as critical or essential to our business as a whole. In general, we depend on our technological capabilities, customer service oriented culture and application of our know-how to distinguish ourselves from our competitors, rather than our right to exclude others through patents or exclusive licenses. We also consider the quality and timely delivery of our products, the service we provide to our customers, and the technical knowledge and skill of our personnel to be more important than our registered intellectual property in our ability to compete.

 

We believe we have become a “go-to” service provider for piloting certain new technologies across North America because of our service quality, execution at the wellsite and scale. These strategic relationships provide us and our customers with access to unique technology from independent innovators. This also allows us to minimize exposure to potential technology adoption risks and the significant costs associated with developing and implementing R&D internally. Our internal resources are focused on evolving our existing proprietary tools to stay on trend and ensure quicker, lower completion and production costs for our customers.

 

Risk Management and Insurance

 

The provision of technical services or use of certain of our tools and equipment in connection therewith could involve operational risk and thereby expose us to liabilities. An accident involving our services or equipment, or the failure of a product, could result in personal injury, loss of life and damage to property, equipment or the environment. Damages from a catastrophic occurrence, such as a fire or explosion, could result in substantial claims for damages. We generally attempt to negotiate the terms of our MSAs consistent with industry practice. In general, we attempt to take responsibility for our own personnel and property, while our customers, such as the E&P companies and well operators, take responsibility for their own personnel, property and all liabilities arising from well and subsurface operations.

 

In addition, claims for loss of oil and gas production and damage to formations can occur in the oilfield services industry. If a serious accident were to occur at a location where our equipment and services are being used, it could result in us being named as a defendant in lawsuits asserting large claims. Because our business involves the transportation of heavy equipment and materials, we may also experience traffic accidents, which may result in spills, property damage and personal injury.

 

Oilfield services companies, despite efforts to maintain high safety standards, from time to time, have suffered accidents. Our business is subject to the same risks and, as a result, there is a risk that we will experience accidents in the future. In addition to the property and personal losses from these accidents, the frequency and severity of these incidents affect our operating costs and insurability, and our relationship with customers, employees and regulatory agencies. In particular, in recent years many of our large customers have placed an increased emphasis on the safety records of their service providers. Any significant increase in the frequency or severity of these incidents, or the general level of compensatory payments, could adversely affect the cost of, or our ability to obtain, workers’ compensation and other forms of insurance, and could have other material adverse effects on our financial condition and results of operations.

 

We maintain a risk management program that covers operating hazards, including products and completed operations, property damage and personal injury claims as well as certain limited environmental claims. Our risk management program includes primary, umbrella and excess umbrella liability policies in excess of $75 million per occurrence, including sudden and accidental pollution claims. We believe that our insurance is sufficient to cover property and casualty liability claims.

 

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We endeavor to allocate potential liabilities and risks between the parties in our MSAs. We retain the risk for any liability not indemnified by our customers and in excess of our insurance coverage. These MSAs delineate our and our customers’ respective warranty and indemnification obligations with respect to the services we provide. We endeavor to negotiate MSAs with our customers that provide, among other things, that we and our customers assume (without regard to fault) liability for damages to our respective personnel and property. For catastrophic losses, we endeavor to negotiate MSAs that include industry-standard carve-outs from the knock-for-knock indemnities. Additionally, our MSAs often provide carve-outs to the “without regard to fault” concept that would permit, for example, us to be held responsible for events of catastrophic loss only if they arise as a result of our gross negligence or willful misconduct. Our MSAs typically provide for industry-standard pollution indemnities, pursuant to which we assume liability for surface pollution associated with our equipment and originating above the surface (without regard to fault), and our customer assumes (without regard to fault) liability arising from all other pollution, including, without limitation, underground pollution and pollution emanating from the wellbore as a result of an explosion, fire or blowout. The summary of MSAs set forth above is a summary of the material terms of the typical MSA that we have in place and does not reflect every MSA that we have entered into or may enter into in the future, some of which may contain indemnity structures and risk allocations between our customers and us that are different than those described here.

 

Information Technology

 

During the fourth quarter of Fiscal 2018 and the second quarter of Fiscal 2019, we successfully completed the integration of the Motley and Red Bone businesses, respectively, onto our company-wide financial accounting platform, which utilizes a Microsoft-based enterprise resource planning (“ERP”) system together with industry leading asset management software “TrakQuip”. These IT systems provide us with a scalable integrated platform that facilitates highly efficient operations, consolidated invoicing and optimal equipment utilization on both a site and segment basis. Our operating strategy is based upon balancing high asset and personnel utilization levels with consistently superior customer service. As such, our IT systems are integral to effectively managing our business.

 

Government Regulation and Environmental, Health and Safety Matters

 

Our operations are subject to extensive and changing federal, state and local laws and regulations establishing health, safety and environmental quality standards, including those governing discharges of pollutants into the air and water and the management and disposal of hazardous substances and wastes. We may be subject to liabilities or penalties for violations of those regulations. We are also subject to laws and regulations, such as the Federal Superfund Law and similar state statutes, governing remediation of contamination, which could occur or might have occurred at facilities that we own or operate, or which we formerly owned or operated, or to which we send or have sent hazardous substances or wastes for treatment, recycling or disposal. We believe that we are currently compliant, in all material respects, with applicable environmental laws and regulations. However, we could become subject to future liabilities or obligations as a result of new or more stringent interpretations of existing laws and regulations. In addition, we may have liabilities or obligations in the future if we discover any environmental contamination or liability relating to our facilities or operations.

 

The following is a summary of some of the existing laws, rules and regulations to which we are subject.

 

Hazardous substances and waste handling

 

The Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes, regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. Under the guidance issued by the Environmental Protection Agency (the “EPA”), the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. We are required to manage the disposal of hazardous and non-hazardous wastes in compliance with RCRA and analogous state laws. RCRA currently exempts many E&P wastes from classification as hazardous waste. Specifically, RCRA excludes from the definition of hazardous waste produced waters and other wastes intrinsically associated with the exploration, development, or production of crude oil and natural gas. However, these oil and gas E&P wastes may still be regulated under state solid waste laws and regulations, and it is possible that certain oil and natural gas E&P wastes now classified as non-hazardous could be classified as hazardous waste in the future. For example, in December 2016, the EPA and

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environmental groups entered into a consent decree to address EPA’s alleged failure to timely assess its RCRA Subtitle D criteria regulations exempting certain E&P related oil and gas wastes from regulation as hazardous wastes under RCRA. The consent decree required the EPA to propose a rulemaking no later than March 15, 2019 for revision of certain Subtitle D criteria regulations pertaining to oil and gas wastes or to sign a determination that revision of the regulations is not necessary. The EPA concluded in 2019 that it does not need to regulate E&P waste, concluding that states are adequately regulating E&P waste under the Subtitle D provisions of RCRA. Stricter regulation of wastes generated during our or our customers’ operations could result in increased costs for our operations or the operations of its customers, which could in turn reduce demand for our services and adversely affect our business.

 

Comprehensive Environmental Response, Compensation, and Liability Act

 

The Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), also known as the Superfund law, imposes joint and several liability, without regard to fault or legality of conduct, on classes of persons who are considered to be responsible for the release of a hazardous substance into the environment. These persons include the current and former owner or operator of the site where the release occurred, and anyone who transported or disposed or arranged for the transport or disposal of a hazardous substance released at the site. Persons who are or were responsible for releases of hazardous substances under CERCLA and any state analogs may be subject to joint and several, strict liability for the costs of cleaning up the hazardous substances that have been released into the environment, and for damages to natural resources and for the costs of certain health studies. We currently own, lease, or operate numerous properties that have been used for manufacturing and other operations for many years. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to remove previously disposed substances and wastes, remediate contaminated property, or perform remedial operations to prevent future contamination. In addition, it is not uncommon for neighboring landowners and other third-parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.

 

Worker health and safety

 

We are subject to a number of federal and state laws and regulations, including the federal Occupational Safety and Health Act (“OSHA”) establishing requirements to protect the health and safety of workers. The OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act and comparable state statutes requires maintenance of information about hazardous materials used or produced in operations and provision of this information to employees, state and local government authorities and citizens. The Federal Motor Carrier Safety Administration regulates and provides safety oversight of commercial motor vehicles, the EPA establishes requirements to protect human health and the environment, the federal Bureau of Alcohol, Tobacco, Firearms and Explosives establishes requirements for the safe use and storage of explosives, and the federal Nuclear Regulatory Commission establishes requirements for the protection against ionizing radiation. Substantial fines and penalties can be imposed and orders or injunctions limiting or prohibiting certain operations may be issued in connection with any failure to comply with these laws and regulations.

 

Transportation safety and compliance

 

Operating a fleet of over 1,000 vehicles, we are subject to a number of federal and state laws and regulations, including the Federal Motor Carrier Safety Regulations and Hazardous Material Regulations for Interstate travel, and comparable state regulations for Intrastate travel. Substantial fines and penalties can be imposed and orders or injunctions limiting or prohibiting certain operations may be issued in connection with any failure to comply with laws and regulations relating to the safe operation of commercial motor vehicles.

 

Water discharges

 

The Federal Water Pollution Control Act (the “Clean Water Act”) and analogous state laws impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances, into waters of the United States. The discharge of pollutants into regulated waters, including jurisdictional wetlands, is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. In

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September 2015, a new EPA and U.S. Army Corps of Engineers (the “Corps”) rule defining the scope of federal jurisdiction over wetlands and other waters became effective (the “Clean Water Rule”). The Clean Water Rule was previously stayed nationwide to determine whether federal district or appellate courts had jurisdiction to hear cases challenging the rule. In October 2019, the EPA and the Corps issued a final rule to repeal the Clean Water Rule (the “Repeal Rule”). With the 2019 Repeal Rule, the agencies report that they will implement prior rules and guidance implemented in 1986 nationwide. Following effectiveness of the Repeal Rule in December 2019, the Clean Water Rule is no longer in effect in any state. Legal challenges to the Repeal Rule have been filed in federal court, and the Repeal Rule could be stayed, remanded or repealed. In January 2020, the EPA and the Corps finalized a rule that would revise the definition of “waters of the United States” and replace both the 1986 rule and the Clean Water Rule (the “2020 Rule”). According to the agencies, the 2020 Rule would increase predictability and consistency under the Clean Water Act by clarifying the scope of waters regulated under the Clean Water Act. The 2020 Rule is subject to several pending legal challenges. The 2020 Rule is intended to narrow the definition of “waters of the United States,” but the potential timing of implementation in light of the pending legal challenge and the eventual effect of the 2020 Rule is unclear. The process for obtaining permits has the potential to delay our operations and those of our customers. Spill prevention, control and countermeasure requirements of federal laws require appropriate containment berms and similar structures to help prevent the contamination of navigable waters by a petroleum hydrocarbon tank spill, rupture or leak. In addition, the Clean Water Act and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. Federal and state regulatory agencies can impose administrative, civil and criminal penalties as well as other enforcement mechanisms for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations. The Clean Water Act and analogous state laws provide for administrative, civil and criminal penalties for unauthorized discharges and, together with the Oil Pollution Act of 1990, impose rigorous requirements for spill prevention and response planning, as well as substantial potential liability for the costs of removal, remediation, and damages in connection with any unauthorized discharges.

 

Air emissions

 

The federal Clean Air Act (“CAA”), and comparable state laws, regulate emissions of various air pollutants through air emissions permitting programs and the imposition of other requirements. In addition, the EPA has developed, and continues to develop, stringent regulations governing emissions of toxic air pollutants at specified sources. These regulations change frequently. These laws and regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements or utilize specific equipment or technologies to control emissions of certain pollutants. For example, in May 2016, the EPA finalized rules regarding criteria for aggregating multiple small surface sites into a single source for air-quality permitting purposes applicable to the oil and gas industry. This rule could cause small facilities, on an aggregate basis, to be deemed a major source, thereby triggering more stringent air permitting requirements. In addition, in October 2015, the EPA lowered the National Ambient Air Quality Standard (“NAAQS”) for ozone from 75 to 70 parts per billion and completed attainment/non-attainment designations in July 2018. State implementation of the revised NAAQS could result in stricter permitting requirements, which in turn could delay or impair our or our customers’ ability to obtain air emission permits, and result in increased expenditures for pollution control equipment, the costs of which could be significant. Federal and state regulatory agencies can impose administrative, civil and criminal penalties, as well as injunctive relief, for non-compliance with air permits or other requirements of the CAA and associated state laws and regulations.

 

Climate change

 

The EPA has determined that emissions of greenhouse gases, including carbon dioxide and methane, present a danger to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the Earth’s atmosphere and other climatic changes. The EPA has established greenhouse gas emission reporting requirements for sources in the oil and gas sector, and has also promulgated rules requiring certain large stationary sources of greenhouse gases to obtain preconstruction permits under the CAA and follow “best available control technology” requirements. Although we are not likely to become subject to greenhouse gas emissions permitting and best available control technology requirements because none of our facilities are presently major sources of greenhouse gas emissions, such requirements could become applicable to our customers and could have an adverse effect

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on their costs of operations or financial performance, thereby adversely affecting our business, financial condition and results of operations. Also, the U.S. Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases and many states already have established regional greenhouse gas “cap-and-trade” programs. The adoption of any legislation or regulation that restricts emissions of greenhouse gases from the equipment and operations of our customers or with respect to the oil and natural gas they produce could adversely affect demand for our products and services. Finally, some scientists have concluded that increasing concentrations of greenhouse gases in the Earth’s atmosphere may produce climate changes that could have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic events; if such effects were to occur, they could have an adverse impact on our operations.

 

Hydraulic fracturing

 

Our businesses are dependent on our customers’ hydraulic fracturing and horizontal drilling activities. Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations, including shales. The process, which involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production, is typically regulated by state oil and natural gas commissions. However, federal agencies have asserted regulatory authority over certain aspects of the process. For example, the EPA has asserted federal regulatory authority pursuant to the federal Safe Drinking Water Act over certain hydraulic fracturing activities involving the use of diesel fuels and published permitting guidance in February 2014 addressing the performance of such activities using diesel fuels. In 2016, the EPA issued final regulations under the CAA establishing performance standards, including standards for the capture of methane emissions released during hydraulic fracturing. In June 2017, the EPA proposed to stay the requirements for a period of two years and revisit implementation of the 2016 methane standards in their entirety. In September 2018, the EPA proposed amendments to relax or rescind certain of the 2016 standards. Various industry and environmental groups have separately challenged both the methane requirements and the EPA’s attempts to delay implementation of the rule. In August 2019, the EPA issued additional proposed amendments that would rescind requirements related to the regulation of methane emissions from the oil and gas industry. Neither of the proposed rulemakings has been finalized, and implementation remains uncertain. The Bureau of Land Management (the “BLM”) previously finalized similar limitations on methane emissions from venting and flaring and leaking equipment from oil and natural gas activities on public lands, but in September 2018, the BLM issued a rule that rescinds or relaxes certain of these limitations. California and New Mexico have challenged the rule in ongoing litigation. As a result, future implementation of both the EPA and BLM methane rules is uncertain at this time. However, given the long-term trend towards increasing regulation, future federal regulation of methane and other greenhouse gas emissions from the oil and gas industry remain a possibility.

 

The EPA has also issued effluent limitation guidelines that prohibit the discharge of wastewater from hydraulic fracturing operations to publicly-owned wastewater treatment plants. In addition, the BLM had previously issued final rules in March 2015 imposing stringent standards for performing hydraulic fracturing on federal and Native American lands; however, the agency finalized a separate rulemaking in December 2017 repealing its hydraulic fracturing rules. Several states and environmental groups have challenged the repeal in federal court. It is unclear how any additional federal regulation of hydraulic fracturing activities may affect our operations, but additional regulatory burdens on our customers could ultimately result in decreased demand for our services.

 

Various studies analyzing the potential environmental impacts of hydraulic fracturing have also been performed. For example, in December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources. The final report concluded that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources “under some circumstances,” noting that the following hydraulic fracturing water cycle activities and local- or regional-scale factors are more likely than others to result in more frequent or more severe impacts: water withdrawals for fracturing in times or areas of low water availability; surface spills during the management of fracturing fluids, chemicals or produced water; injection of fracturing fluids into wells with inadequate mechanical integrity; injection of fracturing fluids directly into groundwater resources; discharge of inadequately treated fracturing wastewater to surface waters; and disposal or storage of fracturing wastewater in unlined pits. As described elsewhere in this Annual Report, these risks are regulated under various state, federal, and local laws.

 

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Some states, counties and municipalities have enacted or are considering moratoria on hydraulic fracturing. For example, New York has banned the use of high volume hydraulic fracturing. Alternatively, some municipalities are or have considered zoning and other ordinances, the conditions of which could impose a de facto ban on drilling and/or hydraulic fracturing operations. Further, some states, counties and municipalities are closely examining water use issues, such as permit and disposal options for processed water, which could have a material adverse impact on our financial condition, prospects and results of operations if such additional permitting requirements are imposed upon our industry. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could reduce our business by making it more difficult or costly for their customers to perform fracturing to stimulate production from tight formations. In addition, if hydraulic fracturing becomes regulated at the federal level as a result of federal legislation or regulatory initiatives by the EPA, the business and operations of our customers could be subject to additional permitting requirements, and also to attendant permitting delays, increased operating and compliance costs and process prohibitions, which could have an adverse effect on our business, financial condition and results of operations.

 

Employees

As of January 31, 2020, we had approximately 1,370 employees. Approximately 85% of our employees are engaged in operations, quality and purchasing, 5% in sales and marketing and 10% in finance, human resources, IT and general administration. Our employees are not unionized, and we consider our employee relations to be good.

 

Available Information

Our filings with the SEC, including this Form 10-K, our Quarterly Reports on Form 10-Q, our Proxy Statement, Current Reports on Form 8-K and amendments to any of those reports are available free of charge on our website, http://www.klxenergy.com, as soon as reasonably practicable after they are filed with, or furnished to, the SEC. These reports may also be obtained on the SEC’s website at www.sec.gov that contains reports, proxy statements, information statements, and other information regarding SEC registrants, including KLX Energy Services Holdings, Inc. Information included in or connected to our website is not incorporated by reference in this annual report.

ITEM 1A.  RISK FACTORS

You should carefully consider each of the following risks and uncertainties, which we believe are the principal risks that we face and of which we are currently aware, and all of the other information in this Form 10‑K. Some of the risks and uncertainties described below relate to our business, while others relate to the spin‑off. Other risks relate principally to the securities markets and ownership of our common stock.

If any of the following events actually occur, our business, financial condition or financial results could be materially adversely affected, the trading price of our common stock could decline and you could lose all or part of your investment. Additional risks and uncertainties that we do not presently know about or currently believe are not material may also adversely affect our business and operations.

Risks Relating to Our Business

We serve customers who are involved in drilling for and production of oil and natural gas. Demand for services in the oil and natural gas industry is cyclical, is currently experiencing a significant downturn and has experienced additional significant downturns in recent years, which are currently significantly affecting, and have in recent years significantly affected, the performance of our business. Additional adverse developments affecting this industry could have a material adverse effect on our business, financial condition and results of operations.

Our revenues are primarily generated from customers who are engaged in drilling for and production of oil and natural gas. Demand for services in the oil and natural gas industry is cyclical and subject to sudden and significant volatility, and we depend on our customers’ willingness to make capital and operating expenditures to explore for, develop and produce oil and natural gas in the United States. Additionally, developments that adversely affect oil and natural gas drilling and production services could reduce our customers’ willingness to make such expenditures and

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materially reduce our customers’ demand for our services and associated product offerings, resulting in a material adverse effect on our business, financial condition and results of operations.

The predominant factor that would reduce demand for our services and associated product offerings would be a reduction in land‑based drilling activity in the continental United States.

 

In recent years, the oil and gas industry has experienced significant downturns. For example, the oilfield service industry experienced an abrupt deterioration in demand during the second half of 2019, which led to a sharp decline in U.S. land rig count and an unprecedented decline in operating frac spreads from the second quarter through the end of 2019. These downturns placed unprecedented pressure on both our customers and competitors.

 

Oil prices declined sharply in March 2020 to levels as low as approximately $21 per barrel as a result of multiple factors affecting levels of supply and demand in global oil and gas markets, including the announcement of price reductions and production increases by OPEC members and other oil exporting nations. Oil and natural gas prices are expected to continue to be volatile as a result of the near term production increases and the ongoing COVID-19 outbreaks and as changes in oil and natural gas inventories, industry demand and national and economic performance are reported, and we cannot predict when prices will improve and stabilize.

 

Worldwide political, economic and military events as well as natural disasters and global or national health pandemics, epidemics or concerns and other factors beyond our control contribute to oil and natural gas price levels and volatility and are likely to continue to do so in the future. Current levels in the price of natural gas, oil or natural gas liquids, as well as ongoing volatility, have had an adverse impact on the level of drilling and E&P activity, which could materially and adversely affect the demand for our services and the rates we are able to charge for our services. We negotiate the rates payable under our contracts based on prevailing market rates, and the rates we are able to charge will fluctuate with market conditions. Furthermore, future higher commodity prices may not necessarily translate into increased drilling activity because our customers’ expectations of future prices also influence their activity. Lower industry demand for oilfield services may persist for a significant period, which would materially adversely affect the rates that we are able to charge and the demand for our services. Additionally, we may incur costs and have downtime any time our customers’ activities are refocused towards different drilling regions.

Significant factors that are likely to affect commodity prices in current and future periods include, but are not limited to, the extent and duration of price reductions and increased production by OPEC members and other oil exporting nations, the effect of U.S. energy, monetary and trade policies, U.S. and global economic conditions, U.S. and global political and economic developments, including the outcome of the U.S. presidential election and resulting energy and environmental policies, the impact of the ongoing COVID-19 outbreaks and conditions in the U.S. oil and gas industry and the resulting demand for domestic land oilfield services. The reduction in oil prices and the ongoing effects of the global COVID-19 outbreaks will likely result in a global recession, with the possibility of numerous bankruptcies of E&P companies and oilfield services companies during 2020 and a significant decline in demand and prices for oilfield services during 2020. We have taken, and are continuing to take, steps to reduce costs, including reductions in capital expenditures, as well as other workforce rightsizing and ongoing cost initiatives.

Another factor that would reduce the level of drilling and production activity is increased government regulation of that activity. Our customers’ drilling and production operations are subject to extensive federal, state, local and foreign laws and government regulations concerning: emissions of pollutants and greenhouse gases; hydraulic fracturing; the handling of oil and natural gas and byproducts thereof and other materials and substances used in connection with oil and natural gas operations, including drilling fluids and wastewater; well spacing; production limitations; plugging and abandonment of wells; unitization and pooling of properties; and taxation. More stringent legislation or regulation (including public pressure on governmental bodies and regulatory agencies to regulate the oil and natural gas industry), a moratorium on drilling or hydraulic fracturing, or increased taxation of oil and natural gas drilling activity could directly curtail such activity or increase the cost of drilling, resulting in reduced levels of drilling activity and therefore reduced demand for our services and associated product offerings.

Spending by E&P companies can also be impacted by conditions in the capital markets. Limitations on the availability of capital, or higher costs of capital, for financing expenditures may cause E&P companies to make

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additional reductions to capital budgets in the future. Cuts in capital spending would likely curtail drilling and completion programs as well as discretionary spending on well construction services, which may result in a reduction in the demand for our services, the rates we can charge and the utilization of our services. Moreover, reduced discovery rates of new oil and natural gas reserves, or a decrease in the development rate of reserves in our market areas, whether due to increased governmental regulation, including with respect to environmental matters, limitations on exploration and drilling activity or other factors, could also have an impact on our business, even in a stronger oil and natural gas price environment. An adverse development in any of these areas could have an adverse impact on our customers’ operations or financial condition, which could in turn result in reduced demand for our services and associated product offerings.

We depend on our customers’ willingness to undertake drilling and completion spending.

Other factors over which we have no control that could affect our customers’ willingness to undertake drilling and completion spending activities include:

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the level of prices, and expectations about prices, for oil and natural gas;

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domestic and foreign supply of and demand for oil and natural gas;

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the level of domestic and global oil and natural gas production;

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the availability, pricing and perceived safety of pipeline, trucking, train storage and other transportation capacity;

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the supply of and demand for oilfield services and equipment;

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lead times associated with acquiring equipment and availability of qualified personnel;

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the cost of exploring for, developing, producing and delivering oil and natural gas;

·

the expected rates of decline in production from existing and prospective wells;

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the discovery rates of new oil and natural gas reserves;

·

federal, state and local regulation of hydraulic fracturing and other oilfield service activities, as well as E&P activities, including public pressure on governmental bodies and regulatory agencies to regulate our industry;

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adverse weather conditions, including rain, tropical storms, hurricanes and severe cold weather, that can affect oil and natural gas operations over a wide area;

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oil refining capacity;

·

merger and divestiture activity among oil and gas producers;

·

the availability of water resources and suitable proppants in sufficient quantities and on acceptable terms for use in hydraulic fracturing operations;

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the availability, capacity and cost of disposal and recycling services for used hydraulic fracturing fluids;

·

the political environment in oil and natural gas producing regions, including uncertainty or instability resulting from civil disorder, terrorism or war;

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worldwide political, military and economic conditions;

·

global or national health pandemics, epidemics or concerns, such as the recent COVID-19 outbreaks, which have reduced and may further reduce demand for oil and natural gas and related products due to reduced global or national economic activity;

·

actions of the Organization of the Petroleum Exporting Countries, its members and other state controlled oil companies relating to oil and natural gas price and production levels, including announcements of potential changes to such levels;

·

advances in exploration, development and production technologies or in technologies affecting energy consumption;

·

activities by non-governmental organizations to restrict the exploration, development and production of oil and natural gas; and

·

the price and availability of alternative fuels and energy sources.

 

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Conservation measures and technological advances could reduce demand for oil and natural gas.

Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas, technological advances in fuel economy and energy generation devices could reduce demand for oil and natural gas. We cannot predict the impact of the changing demand for oil and natural gas services, and any major changes may have a material adverse effect on our business, financial condition and results of operations.

Our business involves many hazards and operational risks.

Conditions inherent in the oil and natural gas industry can cause personal injury or loss of life, disruption or suspension in operations, damage to geological formations, damage to facilities, substantial revenue loss, business interruption and damage to, or destruction of, property, equipment and the environment. Our operations are subject to many hazards and risks, including the following:

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equipment defects;

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accidents resulting in serious bodily injury and the loss of life or property;

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damaged or lost equipment;

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liabilities from accidents or damage by our operators or equipment;

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pollution and other damage to the environment;

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well blowouts and the uncontrolled flow of natural gas, oil or other well fluids into or through the environment, including onto or into the ground or into the atmosphere, groundwater, surface water or an underground formation;

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fires, explosions and cratering;

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mechanical or technological failures;

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loss of well control;

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spillage handling and disposing of materials;

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collapse of the boreholes;

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adverse weather conditions; and

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failure of our employees to comply with our internal environmental, health and safety guidelines.

 

If any of these hazards materialize, they could result in the suspension of operations, termination of contracts without compensation, damage to or destruction of our equipment and the property of others, or injury or death to our personnel or third-parties and could expose us to substantial liability or losses. Although we customarily include a waiver of consequential damages in our customer contracts, defects or other performance problems in the services that we offer or products we offer could result in our customers seeking to invalidate such waiver and seek damages from us for losses associated with these defects or other performance problems. The frequency and severity of such incidents will affect operating costs, insurability and relationships with customers, employees and regulators. Our customers may elect not to purchase our services if they view our safety record as unacceptable or otherwise experience material defects in our products or performance problems, which could cause us to lose customers and substantial revenue, and any litigation or claims, even if fully indemnified or insured, could negatively affect our reputation with our customers and the public and make it more difficult for us to compete effectively or obtain adequate insurance in the future. In addition, these risks may be greater for us upon the acquisition of another company that has not allocated significant resources and management focus to safety and has a poor safety record.

 

We maintain what we believe is customary and reasonable insurance to protect our business against most potential losses, but such insurance may not be adequate to cover our liabilities, especially as the inherent risks in our operations increase with increasing well complexity, and we are not fully insured against all risks inherent in our business. For example, although we are insured for environmental pollution resulting from certain environmental accidents that occur on a sudden and accidental basis, we may not be insured against all environmental accidents or events that might occur, some of which may result in toxic tort claims. If a significant accident or event occurs for which we are not adequately insured, it could adversely affect our financial condition and results of operations. Furthermore, we may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. As a result of market conditions, premiums and deductibles for certain of our insurance policies may substantially increase. In some

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instances, certain insurance could become unavailable or available only for reduced amounts of coverage.

 

Our insurance has deductibles or self-insured retentions and contains certain coverage exclusions. The current trend in the insurance industry is towards larger deductibles and self-insured retentions. In addition, insurance may not be available in the future at rates that we consider reasonable and commercially justifiable, compelling us to have larger deductibles or self-insured retentions to effectively manage expenses. As a result, we could become subject to material uninsured liabilities or situations where we have high deductibles or self-insured retentions that expose us to liabilities that could have a material adverse effect on our business, financial condition and results of operations.

 

In recent years, oilfield services companies have been the subject of a significant volume of wage and hour-related litigation, including claims brought under the Federal Labor Standards Act, in which employee pay practices have been challenged. We have been named as defendants in these lawsuits, and we do not maintain insurance for alleged wage and hour-related litigation. Some of these cases remain outstanding and are in various stages of negotiation and/or litigation. The frequency and significance of wage- or other employment-related claims may affect expenses, costs and relationships with employees and regulators. Additionally, we could become subject to material uninsured liabilities that could have a material adverse effect on our business, financial condition and results of operations.

 

Increased labor costs or the unavailability of skilled workers could hurt our business, financial condition and results of operations.

We are dependent upon a pool of available skilled employees to operate and maintain our business. We compete with other oilfield services businesses and other similar employers to attract and retain qualified personnel with the technical skills and experience required to provide the highest quality service. The demand for skilled workers is high and the supply is limited, and a shortage in the labor pool of skilled workers or other general inflationary pressures or changes in applicable laws and regulations could make it more difficult for us to attract and retain personnel and could require us to enhance our wage and benefits packages thereby increasing our operating costs.

Although our employees are not covered by a collective bargaining agreement, union organizational efforts could occur and, if successful, could increase our labor costs. A significant increase in the wages paid by competing employers or the unionization of groups of our employees could result in increases in the wage rates that we must pay. Likewise, laws and regulations to which we are subject, such as the Fair Labor Standards Act, which governs such matters as minimum wage, overtime and other working conditions, can increase our labor costs or subject us to liabilities to our employees. Our operations are also exposed to risks of claims for alleged employment-related liabilities, including risks of claims related to alleged wrongful termination or discrimination, wage payment practices, retaliation claims and other human resource related matters. We cannot assure you that labor costs will not increase. Increases in our labor costs or unavailability of skilled workers could impair our capacity, diminish our profitability and have a material adverse effect on our business, financial condition and results of operations. 

We may be unable to retain personnel who are key to our operations.

Our success, among other things, is dependent on our ability to attract, develop and retain highly qualified senior management and other key personnel. Competition for key personnel is intense, and our ability to attract and retain key personnel is dependent on a number of factors, including prevailing market conditions and compensation packages offered by companies competing for the same talent. The inability to hire, develop and retain these key employees may adversely affect our business, financial condition and results of operations.

 

We have operated at a loss, and there is no assurance of our profitability in the future.

We have experienced periods of low demand for our services and have incurred operating losses. As discussed above, current commodity prices and the effects of the COVID-19 outbreaks are likely to result in a global recession with the potential for numerous E&P and oilfield services company bankruptcies and a significant decline in demand and prices for our services in 2020. See “—We serve customers who are involved in drilling for and production of oil and natural gas. Demand for services in the oil and natural gas industry is cyclical, is currently experiencing a significant downturn and has experienced additional significant downturns in recent years, which are currently significantly

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affecting, and have in recent years significantly affected, the performance of our business. Additional adverse developments affecting this industry could have a material adverse effect on our business, financial condition and results of operations.” We may not be able to reduce our costs or increase our revenues sufficiently to achieve profitability and generate positive operating income. We may incur further operating losses and experience negative operating cash flow, which may be significant. We cannot predict the ultimate magnitude or duration of the severe decline in oil and gas prices and the ongoing COVID-19 outbreaks or when our business may no longer be adversely affected.

Our business may be adversely affected by a deterioration in general economic conditions or a weakening of the broader energy industry.

The reduction in oil prices to current levels and the ongoing effects of the global COVID-19 outbreaks will likely result in a global recession, with the possibility of numerous bankruptcies of E&P companies and oilfield services companies during 2020 and a significant decline in demand and prices for oilfield services during 2020. The risks associated with our business are more acute during periods of economic slowdown or recession because such periods may be accompanied by decreased spending by our customers. A prolonged period of economic slowdown and/or recession in the United States, particularly if coupled with a prolonged slowdown in the E&P industry, would materially and adversely impact our business, financial condition and results of operations.

The oil and gas industry has historically been both cyclical and seasonal. Activity levels historically have been driven primarily by E&P company capital spending, well completions and workover activity, the geological characteristics of the producing wells and their effect on the services required to commence and maintain production levels, and our customers’ capital and operating budgets. All of these indicators are generally driven by commodity prices, which are affected by both domestic and global supply and demand factors. In particular, while U.S. oil and natural gas prices are correlated with global oil price movements, they are also affected by local market weather and consumption patterns.

Over the past several years, and particularly during the latter half of 2019, an increasing number of E&P companies increased their focus on generating free cash flow; as a result, if oil prices drop or spending for activities exceeds budgeted amounts earlier in their fiscal years, many E&P companies will sharply curtail spending, which negatively impacts demand for our services. This practice has been commonly referred to as “budget exhaustion” in the industry. The lack of notice of budget exhaustion negatively impacts our hiring practices and operating efficiencies. As an example, revenues and operating earnings in the first half of Fiscal 2019 were $310.7 million and $13.4 million, respectively, as compared to revenues and operating loss (exclusive of $47.0 million of intangible asset impairment charges) in the second half of Fiscal 2019 of $233.3 million and $(42.1) million, respectively.

We may need to obtain additional capital or financing to fund expansion of our asset base, which could increase our financial leverage, or we may not be able to finance our capital needs.

Prior to the spin-off, we were a segment of KLX, who funded our capital expenditures. In order to expand our asset base, we may need to make significant capital expenditures. If we do not make sufficient or effective capital expenditures, we will be unable to organically expand our business operations.

We intend to fund our future capital expenditures primarily with cash flows from operating activities and existing cash balances. To the extent our cash and cash flows from operating activities are not sufficient, we could borrow under our $100.0 million senior secured asset-based lending facility (the “ABL Facility”). Availability under the ABL Facility is determined primarily by a borrowing base formula calculated based on a percentage of our accounts receivable and inventory ($60.0 million as of January 31, 2020). The amount of availability under our ABL Facility will be reduced by the greater of $10.0 million or 15% of the borrowing base during any period for which our fixed charge coverage ratio is not at least 1:1 for the trailing four quarters for which financial statements have been delivered. While our fixed charge coverage ratio exceeded 1:1 for the trailing four quarters ended January 31, 2020, to the extent our Consolidated EBITDA for future quarters declines as compared to the same period in the prior year, such as due to declining revenues from the current ongoing macro-economic factors, our fixed charge coverage ratio for the trailing four quarter period may fall below 1:1, in which case, the amount of availability under the ABL Facility would be reduced by the greater of $10.0 million or 15% of the borrowing base until we regain compliance with the 1:1 fixed

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charge coverage ratio as measured upon the delivery of our quarterly or annual financial statements. If our cash, cash flows from operating activities and borrowings under the ABL Facility are not sufficient to fund our capital expenditures, we would be required to fund these expenditures through the incurrence of additional debt or the issuance of debt or equity securities or pursue alternative financing plans, such as refinancing or restructuring future debt, selling assets or reducing or delaying acquisitions or capital investments, such as planned upgrades or acquisitions of equipment and refurbishments of equipment, even if previously publicly announced.

The terms of the indenture that governs our 11.5% senior secured notes due 2025 (the “Notes”), the credit agreement that governs the ABL Facility and the agreements that will govern any future debt and equity instruments may restrict us from adopting some of these alternatives. If debt and equity capital or alternative financing plans are not available on favorable terms or at all, we would be required to either get the necessary consents to amend the terms of our debt to allow us to pursue additional financing alternatives or curtail our capital spending, and our ability to sustain or improve our profits may be adversely affected. Our ability to refinance or restructure our debt will depend on the condition of the capital markets and our financial condition at such time, among other things. Any refinancing of our debt could be at higher interest rates and may require us to comply with onerous covenants, which could further restrict our business operations. In addition, incurring additional debt would result in increased interest expense and financial leverage, and issuing common stock may result in significant dilution to our current stockholders.

If we fail to continue to meet all applicable listing requirements, our common stock may be delisted from The Nasdaq Global Select Market, which could have an adverse impact on the liquidity and trading price of our common stock.

Our common stock is currently listed on The Nasdaq Global Select Market, which has qualitative and quantitative listing criteria. If we are unable to meet any of the Nasdaq listing requirements in the future, including, for example, if the closing bid price for our common stock falls below $1.00 per share for 30 consecutive trading days, Nasdaq could determine to delist our common stock. On March 20, 2020, the closing bid price for our common stock on The Nasdaq Global Select Market was $0.97. A delisting of our common stock could negatively impact us by, among other things, reducing the liquidity and market price of our common stock, reducing the number of investors willing to hold or acquire our common stock, which could negatively impact our ability to raise equity financing or to use our common stock as consideration for acquisitions, decreasing the amount of news and analyst coverage of the company, and limiting our ability to issue additional securities or obtain additional financing in the future.

We face risks from activism against and negative investor sentiment towards the oil and gas industry.

Opposition towards oil and gas drilling and development activity has been growing globally and is particularly pronounced in the U.S. Furthermore, certain segments of the investor community have developed negative sentiment towards investing in the oil and gas industry. Companies in the oil and gas industry have frequently been the target of activist efforts regarding safety, environmental matters, sustainability, human rights and business practices. In addition, some investors, including certain investment advisers, sovereign wealth funds, pension funds, university endowments and family foundations have introduced policies to disinvest in the oil and gas sector for stated social and environmental considerations. Commercial and investment banks have also faced pressure to stop financing oil and gas production and related projects. Such developments, along with environmental activism and climate change and air pollution initiatives, could have an adverse effect on the trading price of our common stock and may also result in a reduction of available capital funding for potential oil and gas development projects, which could reduce demand for our services. If activism against oil and gas exploration and production persists or increases, it could have a material adverse effect on our business, financial condition and results of operations.

Shortages or increases in the costs of the equipment we use in our operations could adversely affect our operations in the future.

We generally do not have specialized tools, trucks or long‑term contracts in place that provide for the delivery of equipment, including, but not limited to, replacement parts and other equipment. We could experience delays in the delivery of the equipment that we have ordered and its placement into service due to factors that are beyond our control. Demand by other oilfield services companies and numerous other factors beyond our control could adversely affect our ability to procure equipment that we have not yet ordered or cause the prices of such equipment to increase. Price increases, delays in delivery and interruptions in supply may require us to increase capital and repair expenditures and

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incur higher operating costs. Each of these could have a material adverse effect on our business, financial condition and results of operations.

We are dependent on a small number of suppliers for key goods and services that we use in our operations.

We do not have long term contracts with third party suppliers of many of the goods and services used in large volumes in our operations, including manufacturers of technical services equipment and fishing tools, chargers and other tools and equipment used in our operations. If demand for goods and services exceeds supply, such as from disruptions to the supply chain or supplier bankruptcies, the availability of certain goods and services used in our industry decreases and the price of such goods and services increases. We are dependent on a small number of suppliers for key goods and services. During the twelve months ended January 31, 2020, based on total purchase cost, our ten largest suppliers of goods and services represented approximately 25% of all such purchases. Our reliance on such suppliers could increase the difficulty of obtaining such goods and services in the event of a disruption to the supply chain or upon a bankruptcy of one or more of these suppliers or upon a shortage in our industry. Price increases, delays in delivery and interruptions in supply may require us to incur higher operating costs. Each of these could have a material adverse effect on our business, financial condition and results of operations.

If suppliers are unable to supply us with the products in our operations in a timely manner, in adequate quantities and/or at a reasonable cost, we may be unable to meet the demands of our customers, which could have a material adverse effect on our business, financial condition and results of operations.

We depend on third-party companies to support our operations through the timely supply of products. Our suppliers may experience capacity constraints that may result in their inability to supply us with products in a timely fashion, with adequate quantities or at a desired price. Factors affecting suppliers can include labor disputes, general economic issues, and changes in raw material and energy costs. Natural disasters such as earthquakes or hurricanes, as well as political instability, global or national health pandemics, epidemics or concerns, such as the recent COVID-19 outbreaks, and terrorist activities, may negatively impact the production or delivery capabilities of our suppliers as well. These factors could lead to increased prices and/or the unfavorable allocation of products by our suppliers, which could reduce our revenues and profit margins and harm our customer relations. Significant disruptions in our supply chain could negatively impact our business, financial condition and results of operations.

Our inability to develop, obtain or implement new technology may cause us to become less competitive.

The energy services industry is subject to the introduction of new drilling, completion and well intervention techniques using new technologies, some of which may be subject to patent protection or costly to obtain. As competitors and others use or develop new technologies in the future, we may be placed at a competitive disadvantage if we fail to keep pace with technological advancements within our industry. Furthermore, we may face competitive pressure to implement or acquire certain new technologies at a substantial cost. Some of our competitors may have greater financial, technical and personnel resources that may allow them to enjoy technological advantages and implement new technologies before we can. We cannot be certain that we will be able to implement new technologies on a timely basis or at an acceptable cost. Thus, limits on our ability to effectively use and implement new and emerging technologies may have a material adverse effect on our business, financial condition and results of operations.

Oilfield anti‑indemnity provisions enacted by many states may restrict or prohibit a party’s indemnification of us.

We typically enter into agreements with our customers governing the provision of our services, which usually include certain indemnification provisions for losses resulting from operations. These agreements may require each party to indemnify the other against certain claims regardless of the negligence or other fault of the indemnified party; however, many states place limitations on contractual indemnity provisions, particularly agreements that indemnify a party against the consequences of its own negligence. Furthermore, certain states, including Louisiana, New Mexico, Texas and Wyoming, have enacted statutes generally referred to as “oilfield anti‑indemnity acts” expressly prohibiting certain indemnity agreements contained in or related to oilfield services agreements. Such oilfield anti‑indemnity acts may restrict or void a party’s indemnification of us, which could have a material adverse effect on our business, financial condition and results of operations.

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Changes in trucking regulations may increase our transportation costs and negatively impact our business, financial condition and results of operations.

For the transportation and relocation of our oilfield services equipment, we operate trucks and other heavy equipment. Therefore, we are subject to regulation as a motor carrier by the U.S. Department of Transportation and by various state agencies, whose regulations include certain permit requirements of highway and safety authorities. These regulatory authorities exercise broad powers over our trucking operations, generally governing such matters as the authorization to engage in motor carrier operations, safety, equipment testing and specifications and insurance requirements. The trucking industry is subject to possible regulatory and legislative changes that may impact our operations, such as changes in fuel emissions limits, the hours of service regulations that govern the amount of time a driver may drive or work in any specific period, limits on vehicle weight and size and other matters.

In addition, regulations issued by environmental regulators can have an adverse impact on our trucking costs, and therefore, on our results of operations. Environmental Protection Agency regulations limiting exhaust emissions became more restrictive in 2010. In 2010, an executive memorandum was signed directing the National Highway Traffic Safety Administration (the “NHTSA”) and the EPA to develop new, stricter fuel efficiency standards for heavy trucks. In 2011, the NHTSA and the EPA adopted final rules that established fuel economy and greenhouse gas standards for medium- and heavy-duty vehicles. These standards apply to model years 2014 to 2018, which are required to achieve an approximate 20% reduction in fuel consumption by model year 2018. In October 2016, the NHTSA and the EPA published new, stricter standards that would apply to trailers beginning with model year 2018 and tractors beginning with model year 2021. As a result of these regulations, we may experience an increase in costs related to truck purchases or rentals and maintenance, an impairment of equipment productivity, a decrease in the residual value of these vehicles and an increase in operating expenses. Proposals to increase federal, state or local taxes, including taxes on motor fuels, are also made from time to time, and any such increase would increase our operating costs. We cannot predict whether, or in what form, any legislative or regulatory changes applicable to our trucking operations will be enacted and to what extent any such legislation or regulations could increase our costs or otherwise adversely affect our business, financial condition and results of operations.

Changes in laws or government regulations regarding hydraulic fracturing could increase our customers’ costs of doing business, limit the areas in which our customers can operate and reduce oil and natural gas production by our customers, which could adversely impact our business, financial condition and results of operations.

The adoption of any future federal, state or local laws or implementation of regulations imposing reporting obligations on, or limiting or banning, the hydraulic fracturing process could make it more difficult for our customers to complete natural gas and oil wells. Any such regulations limiting or prohibiting hydraulic fracturing could reduce oil and natural gas E&P activities by our customers and, therefore, adversely affect our business, financial condition and results of operations. Such laws or regulations could also materially increase our costs of compliance and doing business by more strictly regulating how hydraulic fracturing wastes are handled or disposed. In addition, regulatory schemes implemented by quasi-governmental entities could be interpreted to prevent us from providing our services in certain jurisdictions, which could adversely affect our business, financial condition and results of operations.

Although hydraulic fracturing currently is generally exempt from regulation under the U.S. Safe Drinking Water Act’s Underground Injection Control program and is typically regulated by state oil and natural gas commissions or similar agencies, several federal agencies have asserted regulatory authority over certain aspects of the hydraulic fracturing process. These include, among others, a number of regulations issued and other steps taken by the EPA over the last five years, including its New Source Performance Standards issued in 2012, its June 2016 rule prohibiting the discharge of wastewater from onshore unconventional oil and natural gas extraction facilities to publicly-owned wastewater treatment plants; and the rule in March 2015 that established new or more stringent standards relating to hydraulic fracturing on federal and American Indian lands (which was the subject of litigation and which the BLM rescinded in December 2017). While the Trump Administration has generally indicated an interest in scaling back or rescinding regulations that inhibit the development of the U.S. oil and gas industry, it is difficult to predict the extent to which such policies will be implemented or the outcome of any litigation challenging such implementation, such as the suit the State of California’s attorney general filed in January 2018 challenging the BLM’s rescission of its March 2015 rule referred to above.

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Moreover, some states and local governments have adopted, and other governmental entities are considering adopting, regulations that could impose more stringent requirements on hydraulic fracturing operations. For example, Texas, Colorado and North Dakota among others have adopted regulations that impose new or more stringent permitting, disclosure, disposal and well construction requirements on hydraulic fracturing operations. States could also elect to prohibit high volume hydraulic fracturing altogether, following the approach taken by the State of New York in 2015. Local land use restrictions, such as city ordinances, may restrict drilling in general and hydraulic fracturing in particular. Some state and federal regulatory agencies have also recently focused on a connection between the operation of injection wells used for oil and natural gas waste disposal and seismic activity. Similar concerns have been raised that hydraulic fracturing may also contribute to seismic activity. In March 2016, the United States Geological Survey identified six states with the most significant hazards from induced seismicity, including Oklahoma, Kansas, Texas, Colorado, New Mexico and Arkansas. In light of these concerns, some state regulatory agencies have modified their regulations or issued orders to address induced seismicity. For example, in December 2016, the Oklahoma Corporation Commission’s Oil and Gas Conservation Division (the “OCC Division”) and the Oklahoma Geologic Survey released well completion seismicity guidance, which requires operators to take certain prescriptive actions, including mitigation, following anomalous seismic activity within 1.25 miles of hydraulic fracturing operations, and in February 2017, the OCC Division issued an order limiting future increases in the volume of oil and natural gas wastewater injected into the ground in an effort to reduce seismic activity in the state. Ongoing lawsuits have also alleged that disposal well operations have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. Increased regulation and attention given to induced seismicity could lead to greater opposition to, and litigation concerning, oil and natural gas activities utilizing hydraulic fracturing or injection wells for waste disposal. The adoption of more stringent regulations regarding hydraulic fracturing and the outcome of litigation over hydraulic fracturing could adversely affect some of our customers and their demand for our products, which could have a material adverse effect on our business, financial condition and results of operations.

We and our customers are subject to federal, state and local laws and regulations regarding issues of health, safety, climate change and the protection of the environment, under which we or our customers may become liable for penalties, damages or costs of remediation or other corrective measures. Changes in such laws or regulations could increase our or our customers’ costs of doing business and adversely impact our business, financial condition and results of operations.

Our operations and our customers’ operations are subject to federal, state and local laws and regulations, including those relating to, among other things, protection of natural resources, wetlands, species listed as “endangered” or “threatened” under the federal Endangered Species Act, the environment, health and safety, waste management, waste disposal and the transportation of waste and other materials. Many of the facilities that are used for our operations are leased, and such leases include varying levels of indemnity obligations to the respective landlords for environmental matters related to our use and occupation of such facilities. Our ongoing operations and our customers’ operations may pose risks of environmental liability, including leakage from operations to surface or subsurface soils, surface water or groundwater. Some environmental laws and regulations may impose strict liability, joint and several liability, or both. Additionally, an increase in regulatory requirements affecting oil and gas exploration and completion activities could significantly delay or interrupt our customers’ operations. Increased costs of regulatory compliance, claims for liability or sanctions for noncompliance and related costs could cause us or our customers to incur substantial costs or losses. Clean-up costs and other damages resulting from any contamination-related liabilities and costs associated with changes in and compliance with environmental laws and regulations could result in the reduction or discontinuation of our or our customers’ operations and in a material adverse effect on our business, financial condition and results of operations.

The U.S. Congress has, from time to time, considered adopting legislation to reduce emissions of greenhouse gases, or GHGs, and almost one-half of the states have already taken legal measures to reduce emissions of GHGs. The EPA has finalized a series of GHG monitoring, reporting and emissions control rules for certain large sources of GHGs. While the Trump Administration has announced that the United States will withdraw from international commitments to reduce GHG emissions, it is not clear how this goal will be accomplished, and many state and local officials have announced their commitment to upholding such commitments. Although it is not possible at this time to estimate how potential future laws or regulations addressing GHG emissions could impact our business, any future federal, state or local laws or regulations that may be adopted to address GHG emissions in areas where our customers operate could require our customers to incur increased compliance and operating costs. Regulation of GHGs could also result in a

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reduction in demand for and production of oil and natural gas, which would result in a decrease in demand for our services. Moreover, incentives to conserve energy or use alternative energy sources could reduce demand for oil and natural gas.

Laws protecting the environment generally have become more stringent over time and could continue to do so, which could lead to material increases in our and our customers’ costs for future environmental compliance and remediation.

We may be required to assume responsibility for environmental and other liabilities of companies we have acquired or will acquire.

We may incur liabilities in connection with environmental conditions currently unknown to us relating to our existing, prior or future operations or those of predecessor companies whose liabilities we may have assumed or acquired. We also could be subject to third‑party and governmental claims with respect to environmental matters, including claims under CERCLA in instances where we are identified as a potentially responsible party. We believe that indemnities provided to us in certain of our pre‑existing acquisition agreements may cover certain environmental conditions existing at the time of the acquisition, subject to certain terms, limitations and conditions. However, if these indemnification provisions terminate or if the indemnifying parties do not fulfill their indemnification obligations, we may be subject to liability with respect to the environmental matters that those indemnification provisions address.

Delays by us or our customers in obtaining permits or the inability by us or our customers to obtain or renew permits could impair our business.

We and our customers are required to obtain permits from one or more governmental agencies in order to perform certain activities. Such permits are typically required by state agencies but can also be required by federal and local governmental agencies. The requirements for such permits vary depending on the type of operations, including the location where our customers’ drilling and completion activities will be conducted. As with all governmental permitting processes, there is a degree of uncertainty as to whether a permit will be granted, the time it will take for a permit to be issued and the conditions that may be imposed in connection with the granting of the permit. Certain regulatory authorities have delayed or suspended the issuance of permits while the potential environmental impacts associated with issuing such permits can be studied and appropriate mitigation measures evaluated. Permitting delays, an inability to obtain or renew permits or revocation of our or our customers’ current permits could cause a loss of revenue and could materially and adversely affect our business, financial condition and results of operations.

We may be unable to maintain existing prices or implement price increases on our services.

Our ability to maintain our existing prices or to implement price increases depends on our customers’ ability and willingness to pay such prices. As a result and given the volatility in the market, we may not be successful in maintaining our existing prices or, in the future, implementing price increases. As discussed above, current commodity prices and the effects of the COVID-19 outbreaks are likely to result in a global recession and a significant decline in demand and prices for our services in 2020, and we cannot predict the ultimate magnitude or duration of the severe decline in oil and gas prices and the ongoing COVID-19 outbreaks on the prices we charge. See “—We serve customers who are involved in drilling for and production of oil and natural gas. Demand for services in the oil and natural gas industry is cyclical, is currently experiencing a significant downturn and has experienced additional significant downturns in recent years, which are currently significantly affecting, and have in recent years significantly affected, the performance of our business. Additional adverse developments affecting this industry could have a material adverse effect on our business, financial condition and results of operations.” The inability to maintain our pricing or to increase our pricing from reduced levels could have a material adverse effect on our business, financial condition and results of operations.

There could also be pressure on our pricing and limitations on our ability to increase prices during future periods of increased market demand when a significant amount of new service capacity, including new well service rigs, wireline units and coiled tubing units, may enter the market. In periods of high demand for oilfield services, a tighter labor market may result in higher labor costs. During such periods, our labor costs could increase at a greater rate than

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our ability to raise prices. Also, we may not be able to successfully increase prices without adversely affecting our activity levels. Even if we are able to increase our prices in future periods, we may not be able to do so at a rate that is sufficient to offset any rising costs, which could have a material adverse effect on our business, financial condition and results of operations.

We operate in highly competitive markets and our failure to compete effectively may negatively impact our business, financial condition and results of operations.

The markets in which we operate are highly competitive. Price competition, equipment availability, location and suitability, experience of the workforce, safety records, reputation, operating integrity and the condition of equipment are all factors used by customers in awarding contracts. Our competitors are numerous and may have greater financial and technological resources than we do. Contracts are traditionally awarded on the basis of competitive bids or direct negotiations with customers. The competitive environment has intensified as recent mergers among E&P companies have reduced the number of available customers and may further increase if E&P company bankruptcies further reduce the number of available customers. The fact that certain oilfield services equipment is mobile and can be moved from one market to another in response to market conditions heightens the competition in the industry. In addition, any increase in the supply of hydraulic fracturing fleets could have a material adverse impact on market prices. This increased supply could also require higher capital investment to keep our services competitive.

Some of our competitors may have greater financial, technical, marketing and personnel resources than we do. The larger size of many of our competitors provides them with cost advantages as a result of their economies of scale and their ability to obtain volume discounts and purchase raw materials at lower prices. As a result, such competitors may have stronger bargaining power with their suppliers and have an advantage over us in pricing as well as securing a sufficient supply of raw materials during times of shortage. Many of our competitors also have better brand name recognition, stronger presence in certain geographic markets, more established distribution networks, larger customer bases, more in-depth knowledge of the target markets, and the ability to provide a much broader array of services. Some of our competitors may also be able to devote greater resources to the research and development, promotion and sale of their services and products and better withstand the evolving industry standards and changes in market conditions as compared to us. Our operations may be adversely affected if our competitors introduce new products or services with better features, performance, prices or other characteristics than our products and services or expand into service areas where we operate. Our operations may also be adversely affected if our competitors are able to respond more quickly to new or emerging technologies and services and changes in customer requirements. Our future success and profitability will partly depend upon our ability to keep pace with our customers’ demands for awarding contracts.

Competitive pressures could reduce our market share or require us to reduce the price of our services and products, particularly during industry downturns, either of which could harm our business, financial condition and results of operations. Significant increases in overall market capacity have also caused active price competition and led to lower pricing and utilization levels for our services and products. The competitive environment has intensified since the industry downturn that began in late 2014, which caused an oversupply of, and reduced demand for, oilfield services, and we have seen substantial reductions in the prices we can charge for our services. Any significant future increase in overall market capacity for completion, intervention and production services may adversely affect our business, financial condition and results of operations.

If we lose significant customers, significant customers materially reduce their purchase orders or significant programs on which we rely are delayed, scaled back or eliminated, our business, financial condition and results of operations may be adversely affected.

Our significant customers change from year to year, depending on the level of E&P activity and the use of our services. For the year ended January 31, 2020, no single customer accounted for more than 10% of our revenues. Our top five customers for the year ended January 31, 2020 together accounted for approximately 29% of our revenues. A reduction in purchases of our products and services by or the loss of one of our larger customers for any reason, such as the current industry conditions and economic downturn, insolvency of a customer, decreased production, changes in drilling practices, loss of a customer as a result of the acquisition of such customer by a purchaser who uses a competitor,

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in-sourcing by customers, a transfer of business to a competitor, failure to adequately service our clients or a strike, could have a material adverse effect on our business, financial condition and results of operations.

We may be unable to effectively and efficiently manage our equipment fleet as we expand our business, which could have an adverse effect on our business, financial condition and results of operations.

We have substantially expanded the size, scope and nature of our business, resulting in an increase in the breadth of our product offerings and an expansion of our business geographically. Business expansion places increasing demands on us to increase the inventories that we carry and/or our equipment fleet. We must anticipate demand well out into the future in order to service our extensive customer base. The inability to effectively and efficiently manage our assets to meet current and future needs of our customers, which may vary widely from what is originally forecast due to a number of factors beyond our control, could have an adverse effect on our business, financial condition and results of operations. 

Increased leverage could adversely impact our business, financial condition and results of operations.

We have $250.0 million principal amount outstanding of Notes due 2025, and we may incur additional debt under our ABL Facility or otherwise to finance our operations or for future expansion, including funding acquisitions. A high degree of leverage could have important consequences to us. For example, it could:

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increase our vulnerability to adverse economic and industry conditions;

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require us to dedicate a substantial portion of cash from operations to the payment of debt service, thereby reducing the availability of cash to fund working capital, capital expenditures and other general corporate purposes;

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limit our ability to obtain additional financing for working capital, capital expenditures, general corporate purposes or acquisitions;

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place us at a disadvantage compared to our competitors that are less leveraged;

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limit our flexibility in planning for, or reacting to, changes in our business and in our industry; and

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make us vulnerable to increases in interest rates if we borrow under our ABL Facility, as any such borrowings would be made at variable interest rates.

 

Our ability to borrow under the ABL Facility will depend upon availability thereunder. The amount of our availability is tied to the aggregate amount of our accounts receivable and inventory that satisfy specified criteria as well as our maintaining a minimum fixed charge coverage ratio. Our ability to make payments on and refinance our current debt and any future debt that we may incur will depend on our ability to generate cash in the future from operations, financings or asset sales. Our ability to generate cash is subject to general economic, financial, competitive, legislative, regulatory and other factors that we cannot control. If we cannot service our debt or repay or refinance our debt as it becomes due, we may be forced to sell assets or take other disadvantageous actions, including (1) reducing financing in the future for working capital, capital expenditures and other general corporate purposes or (2) dedicating an unsustainable level of our cash flow from operations to the payment of principal and interest on our indebtedness. The lenders or other investors who hold debt that we fail to service or on which we otherwise default could also accelerate amounts due, which could in such an instance potentially trigger a default or acceleration of other debt we may incur.

 

The indenture that governs the Notes and the credit agreement that governs the ABL Facility have significant financial and operating restrictions that may have an adverse effect on our business, financial condition and results of operations.

 

The indenture that governs the Notes and the credit agreement that governs the ABL Facility contain financial, operating and/or negative covenants that limit our ability to incur indebtedness, to create liens or other encumbrances, to make certain payments and investments, including dividend payments, to engage in transactions with affiliates, to engage in sale/leaseback transactions, to guarantee indebtedness and to sell or otherwise dispose of assets and merge or consolidate with other entities. Agreements governing our future indebtedness could also contain significant financial and operating restrictions. A failure to comply with the obligations contained in any such agreement governing our indebtedness could result in an event of default under such agreement, which could permit acceleration of the related

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debt, enforcement against any liens securing the related debt and acceleration of debt under other instruments that may contain cross acceleration or cross default provisions. We may not have, or may not be able to obtain, sufficient funds to make any required accelerated payments.

 

Our success may be affected by our ability to use and protect our proprietary technology as well as our ability to enter into license agreements.

 

Our success may be affected by our development and implementation of new product designs and improvements and by our ability to protect, obtain and maintain intellectual property assets related to these developments. We rely on a combination of patents and trade secret laws to establish and protect proprietary technology. We have received patents and have filed patent applications with respect to certain aspects of our technology, and we generally rely on patent protection with respect to our proprietary technology, as well as a combination of trade secrets, employee and third-party non-disclosure agreements and other protective measures to protect intellectual property rights

pertaining to our products and technologies. We cannot assure you that competitors will not infringe upon, misappropriate, violate or challenge our intellectual property rights in the future. If we are not able to adequately protect or enforce our intellectual property rights, such intellectual property rights may not provide significant value to our business, financial condition and results of operations.

 

Moreover, our rights in our confidential information, trade secrets and confidential know-how will not prevent third-parties from independently developing similar technologies or duplicating such technologies. Publicly available information (e.g., information in issued patents, published patent applications and scientific literature) can be used by third-parties to independently develop technology, and we cannot provide assurance that this independently developed technology will not be equivalent or superior to our proprietary technology. In addition, while we have patented some of our key technologies, we do not patent all of our proprietary technology, even when regarded as patentable. The process of seeking patent protection can be long and expensive. There can be no assurance that patents will be issued from currently pending or future applications or that, if patents are issued, they will be of sufficient scope or strength to provide meaningful protection or any commercial advantage to us. Further, with respect to exclusive third-party arrangements, these arrangements could be terminated, which would result in our inability to provide the services and/or products covered by such arrangements.

 

We may be adversely affected by disputes regarding intellectual property rights and the value of our intellectual property rights is uncertain.

 

We may become involved in dispute resolution proceedings from time to time to protect and enforce our intellectual property rights. In these dispute resolution proceedings, a defendant may assert that our intellectual property rights are invalid or unenforceable. Third-parties from time to time may also initiate dispute resolution proceedings against us by asserting that our business infringes, impairs, misappropriates, dilutes or otherwise violates another party’s intellectual property rights. We may not prevail in any such dispute resolution proceedings, and our intellectual property rights may be found invalid or unenforceable or our products and services may be found to infringe, impair, misappropriate, dilute or otherwise violate the intellectual property rights of others. The results or costs of any such

dispute resolution proceedings may have an adverse effect on our business, financial condition and results of operations. Any dispute resolution proceeding concerning intellectual property could be protracted and costly, is inherently unpredictable and could have an adverse effect on our business, financial condition and results of operations, regardless of its outcome.

 

The Motley, Red Bone and Tecton acquisitions and any future acquisitions may not be successful in delivering expected performance post-acquisition, which could have a material adverse effect on our business, financial condition and results of operations.

Our business was created largely through a series of acquisitions. We regularly evaluate acquisition opportunities, frequently engage in acquisition discussions and conduct due diligence activities and, where appropriate, engage in acquisition negotiations, some of which could be material to us. Our ability to continue to achieve our goals may depend upon our ability to effectively identify attractive businesses, access financing sources on acceptable terms,

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negotiate favorable transaction terms and successfully integrate any businesses we acquire, achieve cost efficiencies and manage these businesses as part of our company.

Our acquisition activities, including our acquisitions of Motley, Red Bone and Tecton, may involve unanticipated delays, costs and other problems. If we encounter unanticipated problems with one of our acquisitions, our senior management may be required to divert attention away from other aspects of our business. We may lose key employees and customers of the acquired businesses, including those of Motley, Red Bone and Tecton, and we may be unable to commercially develop acquired technologies. We also risk entering markets in which we have limited prior experience. Additionally, we may fail to consummate proposed acquisitions or divestitures, after incurring expenses and devoting substantial resources, including management time, to such transactions. Acquisitions also pose the risk that we may be exposed to successor liability relating to actions by an acquired company and its management before the acquisition. The due diligence we conduct in connection with an acquisition, and any contractual guarantees or indemnities that we receive from the sellers of acquired companies, may not be sufficient to protect us from, or compensate us for, actual liabilities that we assume or incur in connection with acquisitions we complete. Additionally, depending upon the acquisition opportunities available, we also may need to raise additional funds through the capital markets or arrange for additional bank financing in order to consummate such acquisitions or to fund capital expenditures necessary to integrate such acquired businesses. We also may not be able to raise the substantial capital required for acquisitions and integrations on satisfactory terms, if at all. In addition, if we elect to utilize shares of common stock or other equity securities as consideration for one or more acquisitions or business combinations, or if we issue common stock or other equity securities in order to finance one or more acquisitions, existing stockholders of our company could experience dilution in the value of their securities, which could be material.

The process of integrating an acquired business may involve unforeseen costs and delays or other operational, technical and financial difficulties and may require a disproportionate amount of management attention and financial and other resources. Our failure to achieve consolidation savings, to incorporate the acquired businesses and assets into our existing operations successfully or to minimize any unforeseen operational difficulties could have a material adverse effect on our business, financial condition and results of operations. Furthermore, there is intense competition for acquisition opportunities in our industry. Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions.

We may experience future impairment charges.

To conduct our business operations and execute our strategy, we acquire tangible and intangible assets, which affect the amount of future period amortization expense and possible impairment expense that we may incur. The risk of impairment may be heightened for the duration of the current industry conditions, which may persist for a prolonged period. The determination of the value of such intangible assets requires management to make estimates and assumptions that affect our financial statements. As part of our strategy, we may make additional acquisitions, which may result in the addition of duplicative assets. In the event such an acquisition results in the combined assets of our Company and the acquired assets being in excess of any reasonable forecast of future need, the excess portion of the book value of these assets may be judged to be impaired. In accordance with Accounting Standards Codification (“ASC”) 360, Property, Plant, and Equipment, we assess potential impairment to long-lived assets (property and equipment and amortized intangible assets) when there is evidence that events or changes in circumstances indicate that the carrying amount of an asset may not be recovered. Our judgment regarding the existence of impairment indicators and future cash flows related to intangible assets is based on operational performance of our acquired businesses, expected changes in the global economy, oil and gas price and industry projections, discount rates and other judgmental factors. We would be required to record any such impairment losses resulting from any such test as a charge to operating results. To perform the annual assessment, we utilize a combination of income and market-based approaches to value the reporting units. The income approach to valuation relies on a discounted cash flow analysis to determine the fair value of each reporting unit, which considers forecasted cash flows discounted at an appropriate discount rate. The annual goodwill impairment test requires us to make a number of assumptions and estimates concerning future levels of revenue growth, operating margins and working capital requirements, which are based upon our long-term strategic plan. The discount rate is an estimate of the overall after-tax rate of return required by a market participant, whose weighted average cost of capital includes both equity and debt, including a risk premium. Any future impairment loss could have a material non-cash adverse impact on our results of operations. As of January 31, 2020, our management believes the estimated fair value of our reporting unit

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with a goodwill balance, our indefinite lived intangible assets and each of our long-lived assets were each in excess of their carrying values. There were no indicators of goodwill or intangible asset impairment at January 31, 2020.

The abrupt deterioration in industry conditions, which began in the third quarter and accelerated through the end of our fourth quarter of Fiscal 2019, was driven by a sharp decline in U.S. land rig count and an unprecedented decline in operating frac spreads from the second quarter through the end of 2019. The decline in E&P activity resulted in lower demand levels and lower current and expected revenues for our business, which led us to accelerate our annual testing for asset impairment into the third quarter. As a result, we reported a non-cash asset impairment charge of $47.0 million in Fiscal 2019. Based on the impairment indicators above, we performed a long-lived asset impairment analysis and concluded that the undiscounted cash flows of the long-lived assets exceeded the carrying amount of each segment’s asset group as of October 31, 2019 and December 31, 2019.

Our total assets include intangible assets. The write-off of a significant portion of intangible assets would negatively affect our reported financial results.

Our total assets include intangible assets. Our intangible assets consist principally of goodwill and other identified intangible assets associated with our acquisitions. On at least an annual basis, we assess whether there has been an impairment in the value of goodwill and other intangible assets with indefinite lives. If the carrying value of the tested asset exceeds its estimated fair value, impairment is deemed to have occurred. In this event, the amount is written down to fair value. Under GAAP, this would result in a non-cash charge to operating earnings. The risk of write-downs may be heightened for the duration of the current industry conditions, which may persist for a prolonged period. Any determination requiring the non-cash write-off of a significant portion of goodwill or unamortized identified intangible assets would negatively affect our results of operations and total capitalization, which could be material. For example, during the year ended January 31, 2020, we recorded a non-cash goodwill impairment charge of $47.0 million. There were no impairment charges recorded in Fiscal 2018 or 2017. As of January 31, 2020, the balances of goodwill and intangible assets were $28.3 million and $45.8 million, respectively.

Our operations rely on an extensive network of information technology resources and a failure to maintain, upgrade and protect such systems could adversely impact our business, financial condition and results of operations. Our operations are subject to cyber security risks that could have a material adverse effect on our business, financial condition and results of operations.

Information technology plays a crucial role in all of our operations. To remain competitive, our hardware, software and related services must interact with our suppliers and customers efficiently, record and process our financial transactions accurately, and obtain the data and information to enable the analysis of trends and plans and the execution of our strategies. Our information technology systems are subject to possible breaches and other threats that could cause us harm. If our systems for protecting against cyber security risks prove not to be sufficient, we could be adversely affected by, among other things, loss or damage of intellectual property, proprietary information, or customer data; interruption of business operations; or additional costs to prevent, respond to, or mitigate cyber security attacks. These risks could have a material adverse effect on our business, financial condition and results of operations. 

We have been expanding our available products and services in recent periods. Our inability to properly manage or support future expansion of our business may have a material adverse effect on our business, financial condition, and results of operations and could cause the market value of our common stock to decline.

We have been expanding our available products and services in recent periods and ay to continue to expand over time through the internal expansion of products and services and potential acquisitions. Any such expansion, if achieved, could place significant demands on our management team and our operational, administrative and financial resources. We may not be able to expand effectively or manage our expansion successfully, and the failure to do so could have a material adverse effect on our business, financial condition and results of operations and could cause the market value of our common stock to decline.

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Our assets require capital for maintenance, upgrades and refurbishment, and we may require capital expenditures for new equipment.

Our equipment requires periodic capital investment in maintenance, upgrades and refurbishment to maintain its competitiveness. Our equipment typically does not generate revenue while it is undergoing maintenance, refurbishment or upgrades. Any maintenance, upgrade or refurbishment project for our assets could increase our indebtedness or reduce cash available for other opportunities. Further, such projects may require proportionally greater capital investments as a percentage of total asset value, which may make such projects difficult to finance on acceptable terms. To the extent we are unable to fund such projects, we may have less equipment available for service or our equipment may not be attractive to potential or current customers. Moreover, if the current period of low demand for our services and challenging business conditions in the energy sector generally persists for a prolonged period, we may be unable to make capital investments. Additionally, competition or advances in technology within our industry may require us to update our products and services. Such demands on our capital or reductions in demand and the increase in cost to maintain labor necessary for such maintenance and improvement, in each case, could have a material adverse effect on our business, financial condition and results of operations.

Competition among oilfield service and equipment providers is affected by each provider’s reputation for safety and quality.

Our activities are subject to a wide range of national, state and local occupational health and safety laws and regulations. In addition, customers maintain their own compliance and reporting requirements. Failure to comply with these health and safety laws and regulations, or failure to comply with our customers’ compliance or reporting requirements, could tarnish our reputation for safety and quality and have a material adverse effect on our competitive position.

Seasonal and adverse weather conditions adversely affect demand for services and operations.

Weather can have a significant impact on demand as consumption of energy is seasonal, and any variation from normal weather patterns, such as cooler or warmer summers and winters, can have a significant impact on demand. Adverse weather conditions, including rain, tropical storms, hurricanes, tornadoes and severe cold weather, may interrupt or curtail operations, our customers’ operations, cause supply disruptions and result in a loss of revenue and damage to our equipment and facilities, which may or may not be insured. Specifically, we typically have experienced a pause by our customers around the holiday season in the fourth quarter, which may be compounded as our customers exhaust their annual capital spending budgets towards year end. Additionally, our operations are directly affected by weather conditions. During the winter months (first and fourth quarters) and periods of heavy snow, ice or rain, particularly in the northeastern U.S., Colorado, North Dakota and Wyoming, our customers may delay operations or we may not be able to operate or move our equipment between locations. Also, during the spring thaw, which normally starts in late March and continues through June, some areas impose transportation restrictions to prevent damage caused by the spring thaw. In addition, throughout the year heavy rains adversely affect activity levels, as well locations and dirt access roads can become impassible in wet conditions.

We may be subject to claims for personal injury and property damage or other litigation, which could materially adversely affect our business, financial condition and results of operations.

Our services are subject to inherent risks that can cause personal injury or loss of life, damage to or destruction of property, equipment or the environment or the suspension of our operations. As the wells we service continue to become more complex, our exposure to such inherent risks becomes greater as downhole risks increase exponentially with an increase in complexity and lateral length. Litigation arising from operations where our facilities are located, or our services are provided, may cause us to be named as a defendant in lawsuits asserting potentially large claims including claims for exemplary damages. For example, transportation of heavy equipment creates the potential for our trucks to become involved in roadway accidents, which in turn could result in personal injury or property damages lawsuits being filed against us.

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Uncertainty related to the LIBOR calculation process and potential phasing out of LIBOR after 2021 may adversely affect the market value of our future debt obligations.

Any borrowings under our ABL Facility will bear interest based on a base rate or a LIBOR based rate. LIBOR is calculated by reference to a market for interbank lending, and it is based on increasingly fewer actual transactions. This reduction increases the subjectivity of the LIBOR calculation process and increases the risk of manipulation. Actions by regulators or law enforcement agencies, as well as the ICE Benchmark Administration (the current LIBOR administrator), may result in changes to how LIBOR is determined or the establishment of alternative reference rates. For example, in 2017, the U.K. Financial Conduct Authority announced that it intends to stop persuading or compelling banks to submit LIBOR rates after 2021. U.S. dollar LIBOR is likely to be replaced by the Secured Overnight Financing Rate (“SOFR”) published by the Federal Reserve Bank of New York, but the timing of this change is unknown. SOFR is an overnight rate rather than a term rate, making it an inexact replacement for LIBOR, and there is not currently an established process for creating robust, forward-looking, SOFR term rates.

Changing the benchmark rate for LIBOR loans from LIBOR to SOFR will require calculations of a spread. Industry organizations are attempting to structure the spread calculation in a manner that minimizes the possibility of value transfer between borrowers, lenders and contractual counterparties as a result of the switch to SOFR, but there can be no assurance that the calculated spread will be fair and accurate. We cannot predict the effect of any such changes, any establishment of alternative reference rates or any other reforms to LIBOR that may be implemented. If LIBOR ceases to exist, we may need to renegotiate our ABL Facility to determine a replacement interest rate for LIBOR with the new standard that is established. If we were unable to agree to an amendment to our ABL Facility to replace LIBOR, any borrowings under our ABL Facility would bear interest at the base rate, which has historically been higher than the LIBOR based rate. The potential effect of any such event or our future borrowing costs for any borrowings under our ABL Facility cannot yet be determined.

Risks Relating to the Spin-Off

We may not achieve some or all of the expected benefits of the spin-off, and the spin-off may adversely affect our business.

We believe that our separation from KLX and operating as an independent, publicly-traded company will enhance our long-term value. However, by separating from KLX, we may be more susceptible to market fluctuations and other adverse events than we would have been were we still a part of KLX. Our performance may not meet our expectations for a variety of reasons. There also can be no assurance that the spin-off will not adversely affect our business.

We have a limited operating history as an independent company and our historical financial information may not be a reliable indicator of our future results.

The historical financial information for periods prior to the spin-off that we have included in this Form 10-K has been derived from KLX’s consolidated financial statements and accounting records and does not necessarily reflect what our financial position, results of operations and cash flows would have been had we been a separate, stand-alone entity during the periods presented. KLX did not account for us, and we were not operated, as a single stand-alone company for the periods presented. Actual costs that may have been incurred if we had been a stand-alone company would depend on a number of factors, including the chosen organizational structure, what functions were outsourced or performed by employees and strategic decisions made in areas such as information technology and infrastructure. In addition, the historical information may not be indicative of what our results of operations, financial position and cash flows will be in the future. For example, following the spin-off, changes have occurred in our cost structure, debt financing and interest expense, funding and operations, including changes in our tax structure and increased costs associated with operating as a public, stand-alone company.

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The spin-off may expose us to potential liabilities arising out of state and federal fraudulent conveyance laws and legal dividend requirements.

The spin-off continues to be subject to review under various state and federal fraudulent conveyance laws. Fraudulent conveyance laws generally provide that an entity engages in a constructive fraudulent conveyance when (1) the entity transfers assets and does not receive fair consideration or reasonably equivalent value in return and (2) the entity (a) is insolvent at the time of the transfer or is rendered insolvent by the transfer, (b) has unreasonably small capital with which to carry on its business or (c) intends to incur or believes it will incur debts beyond its ability to repay its debts as they mature. An unpaid creditor or an entity acting on behalf of a creditor (including, without limitation, a trustee or debtor-in-possession in a bankruptcy by us or KLX or any of our respective subsidiaries) may bring a lawsuit alleging that the spin-off or any of the related transactions constituted a constructive fraudulent conveyance. If a court accepts these allegations, it could impose a number of remedies, including, without limitation, voiding our claims against KLX, requiring our stockholders to return to KLX some or all of the shares of our common stock issued in the spin-off, or providing KLX with a claim for money damages against us in an amount equal to the difference between the consideration received by KLX and the fair market value of our company at the time of the spin-off.

The measure of insolvency for purposes of the fraudulent conveyance laws vary depending on which jurisdiction’s law is applied. Generally, an entity would be considered insolvent if: (1) the present fair saleable value of its assets is less than the amount of its liabilities (including contingent liabilities); (2) the present fair saleable value of its assets is less than its probable liabilities on its debts as such debts become absolute and matured; (3) it cannot pay its debts and other liabilities (including contingent liabilities and other commitments) as they mature; or (4) it has unreasonably small capital for the business in which it is engaged. We cannot assure you what standard a court would apply to determine insolvency or that a court would determine that we, KLX or any of our respective subsidiaries were solvent at the time of or after giving effect to the spin-off.

The distribution of our common stock in the spin-off is also subject to review under state corporate distribution statutes. Under the DGCL, a corporation may only pay dividends to its stockholders either (1) out of its surplus (net assets minus capital) or (2) if there is no such surplus, out of its net profits for the fiscal year in which the dividend is declared and/or the preceding fiscal year. Although KLX made the distribution of our common stock entirely from surplus, we cannot assure you that a court will not later determine that some or all of the distribution to KLX stockholders was unlawful.

Each of KLX and KLX Energy Services determined that it was solvent at the time of the spin-off (including immediately after the distribution of shares of KLX Energy Services common stock), will be able to repay its debts as they mature following the spin-off and have sufficient capital to carry on its businesses and the spin-off, and the distribution was made entirely out of surplus in accordance with Section 170 of the DGCL. The expectations of the board of directors of KLX in this regard were based on a number of assumptions, including its expectations as to the post-spin-off operating performance and cash flow of each of KLX and KLX Energy Services and its analysis of the post-spin-off assets and liabilities of each company. We cannot assure you, however, that a court would reach the same conclusions as the board of directors of KLX in determining whether KLX or we were insolvent at the time of, or after giving effect to, the spin-off or whether lawful funds were available for the separation and the distribution to KLX’s stockholders.

A court could require that we assume responsibility for obligations allocated to KLX under the Distribution Agreement.

Under the Distribution Agreement, from and after the spin-off, each of KLX (now a wholly owned subsidiary of The Boeing Company) and we are responsible for the debts, liabilities and other obligations related to the business or businesses which it owns and operates following the consummation of the spin-off. Although we do not expect to be liable for any obligations that are not allocated to us under the Distribution Agreement, a court could disregard the allocation agreed to between the parties and require that we assume responsibility for obligations allocated to KLX (including, for example, environmental liabilities), particularly if KLX were to refuse or were unable to pay or perform the allocated obligations.

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Risks Relating to Our Common Stock

 

Future sales of our common stock in the public market could reduce our stock price, and any additional capital raised by us through the sale of equity or convertible securities may dilute your ownership in us.

 

We may sell shares of common stock in the future. We may also issue additional shares of common stock, including as employee compensation or as consideration in one or more acquisitions or other business combination transactions. As of January 31, 2020, we had outstanding approximately 25.0 million shares of our common stock. We also have registered 3,225,000 shares of common stock reserved for issuance under our LTIP, 200,000 registered shares of common stock are reserved for issuance under our Employee Stock Purchase Plan and 300,000 registered shares are reserved for issuance under our Non-Employee Directors Stock and Deferred Compensation Plan. Of those shares initially registered and reserved for issuance, as of January 31, 2020,  approximately 3,085,000 restricted shares of common stock were granted in connection with equity awards to management, directors and employees and approximately 230,000 shares remain available for future issuance. The restricted shares outstanding include approximately 1,985,000 shares of restricted stock that were granted to certain members of our management under our LTIP on September 14, 2018, the spin-off distribution date, aggregating approximately 8% of our shares outstanding on January 31, 2020. The shares of restricted stock granted on the distribution date will vest ratably over four years from the distribution date, with one quarter of the shares vesting on each anniversary of the distribution date, subject to accelerated vesting under certain circumstances. In addition, the final installment of consideration for the Motley acquisition ($3.0 million) payable to certain employees of Motley in shares of our common stock will be made in November 2020, the second anniversary of the closing of the Motley transaction. The number of shares to be issued will be determined based on the volume weighted average trading price of our shares for the 10 trading days ending two trading days prior to the issuance of the shares. We may, at our option, elect to pay the installment in cash in lieu of issuing the shares.

 

Subject to the satisfaction of vesting conditions and the requirements of Rule 144, the registered restricted shares of our common stock will be available for resale immediately in the public market without restriction. With respect to shares of restricted stock granted to certain members of our management, we have filed a resale prospectus in order to allow such members of our management to freely resell their restricted stock once it has vested. In addition, certain members of our management are entitled to registration rights with respect to their shares of restricted stock.

 

We cannot predict the size of future issuances of our common stock or securities convertible into common stock or the effect, if any, that future issuances and sales of shares of our common stock will have on the market price of our common stock. Sales of substantial amounts of our common stock (including shares issued in connection with an acquisition), or the perception that such sales could occur, may adversely affect prevailing market prices of our common stock. Sales of or other transactions relating to shares of our common stock by our directors, officers or employees could cause a perception in the market place that adverse events or trends have occurred or may be occurring at our company or that it is otherwise an advantageous time to sell shares of our common stock.

 

We cannot assure you that we will pay dividends on our common stock, and our indebtedness could limit our ability to pay dividends on our common stock.

 

We do not currently intend to pay dividends. Our dividend policy will be established by our Board based on our financial condition, results of operations and capital requirements, as well as applicable law, regulatory constraints, industry practice and other business considerations that our Board considers relevant. In addition, the terms of the agreements governing our debt limit, and the terms of the agreements governing any future debt may limit or prohibit, the payments of dividends. We cannot assure you that we will pay dividends in the future or continue to pay any dividends if we do commence the payment of dividends.

 

Additionally, our indebtedness could have important consequences for holders of our common stock. If we cannot generate sufficient cash flow from operations to meet our debt payment obligations, then our Board’s ability to declare dividends on our common stock will be impaired and we may be required to attempt to restructure or refinance our debt, raise additional capital or take other actions such as selling assets, reducing or delaying capital expenditures or reducing any proposed dividends. We cannot assure you that we will be able to effect any such actions or do so on

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satisfactory terms, if at all, or that such actions would be permitted by the terms of our debt or our other credit and contractual arrangements.

 

Certain provisions contained in our amended and restated certificate of incorporation and amended and restated bylaws, and certain provisions of Delaware law may prevent or delay an acquisition of our company or other strategic transactions, which could decrease the trading price of our common stock.

 

Our amended and restated certificate of incorporation and amended and restated bylaws contain, and Delaware law contains, provisions that are intended to deter coercive takeover practices and inadequate takeover bids and to encourage prospective acquirers to negotiate with our Board rather than to attempt a hostile takeover.

 

In addition, because we have not chosen to be exempt from Section 203 of the DGCL, this provision could also delay or effectively prevent a change of control that some stockholders may favor. In general, Section 203 provides that, subject to limited exceptions, persons that, together with their affiliates and associates, acquire ownership of 15% or more of the outstanding voting stock of a Delaware corporation shall not engage in any “business combination” with that corporation or its subsidiaries, including any merger or various other transactions, for a three-year period following the date on which that person became the owner of 15% or more of the corporation’s outstanding voting stock.

 

We believe these provisions will protect our stockholders from coercive or otherwise unfair takeover tactics by requiring potential acquirers to negotiate with our Board and by providing our Board with more time to assess any acquisition proposal. These provisions are not intended to make us immune from takeovers. However, these provisions will apply even if the offer may be considered beneficial by some stockholders and could delay or effectively prevent an acquisition that our Board determines is not in the best interests of our company and our stockholders. These provisions may also prevent or discourage attempts to remove and replace incumbent directors.

 

Our amended and restated bylaws designate courts in the State of Delaware as the sole and exclusive forum for certain types of actions and proceedings that may be initiated by our stockholders, which could limit our stockholders’ ability to obtain a different judicial forum for intra-corporate disputes with us or our directors, officers, employees or agents.

 

Our amended and restated bylaws provide that, unless we otherwise consent in writing to selection of an alternative forum, the Court of Chancery in the State of Delaware (or, if the Court of Chancery does not have jurisdiction, the federal district court for the District of Delaware) will be the sole and exclusive forum for any derivative action or proceeding brought on behalf of KLX Energy Services, any action asserting a claim of breach of a fiduciary duty owed by any director, officer, employee or agent of KLX Energy Services to KLX Energy Services or KLX Energy Services’ stockholders, any action asserting a claim arising pursuant to any provision of the Delaware General Corporation Law (the “DGCL”), KLX Energy Services’ certificate of incorporation or the bylaws, or any action asserting a claim governed by the internal affairs doctrine. This provision may limit a stockholder’s ability to bring a claim in a different judicial forum, including one that it may find favorable or convenient for intra-corporate disputes with us or our directors, officers, employees or agents, which may discourage such lawsuits. Alternatively, if a court were to find this provision of our amended and restated bylaws inapplicable to, or unenforceable in respect of, one or more of the specified types of actions or proceedings, we may incur additional costs associated with resolving such matters in other jurisdictions.

 

Utilizing the reduced disclosure requirements applicable to “emerging growth companies” may make our common stock less attractive to investors.

 

We qualify as an “emerging growth company” and are therefore eligible to utilize certain reduced reporting and other requirements that are otherwise applicable generally to public companies. Pursuant to these reduced disclosure requirements, emerging growth companies are not required to, among other things, hold stockholder advisory votes on executive compensation or obtain stockholder approval of any golden parachute payments not previously approved. In addition, emerging growth companies have longer phase-in periods for the adoption of new or revised financial accounting. We would cease to be an emerging growth company if we have more than $1.07 billion in annual revenue,

36

have more than $700 million in market value of our common stock held by non-affiliates or issue more than $1.0 billion of non-convertible debt over a three-year period.

 

We intend to utilize certain of the reduced reporting requirements and exemptions, including the longer phase-in periods for the adoption of new or revised financial accounting standards, until we are no longer an emerging growth company. If we were to subsequently elect instead to comply with these public company effective dates, such election would be irrevocable.

 

We cannot predict if investors will find our common stock less attractive if we elect to rely on these exemptions. If some investors find our common stock less attractive as a result, there may be a less active trading market for our common stock and our common stock price may be more volatile.

 

If securities or industry analysts do not publish research reports or publish unfavorable research about our business, the price and trading volume of our common stock could decline.

 

The trading market for our common stock depends in part on the research reports that securities or industry analysts publish about us or our business. If one or more of the analysts who covers us downgrades our securities, the price of our securities would likely decline. If one or more of these analysts ceases to cover us or fails to publish regular reports on us, interest in the purchase of our securities could decrease, which could cause the price of our common stock and its trading volume to decline.

 

ITEM 1B.  UNRESOLVED STAFF COMMENTS

 

None.

37

ITEM 2.  PROPERTIES

As of January 31, 2020, we had 34 principal operating facilities. The following table describes the principal facilities and indicates the location and ownership type of each location.

 

 

 

 

 

 

City

    

Segment

    

Ownership

 

El Reno, OK

 

Northeast/Mid-Con

 

Lease

 

Pecos, TX

 

Southwest

 

Lease

 

Williston, ND

 

Rocky Mountains

 

Lease

 

Pleasanton, TX

 

Southwest

 

Own

 

Hallsville, TX

 

Northeast/Mid-Con

 

Lease

 

Johnstown, CO

 

Rocky Mountains

 

Own

 

Midvale, OH

 

Northeast/Mid-Con

 

Lease

 

Bridgeport, WV

 

Northeast/Mid-Con

 

Lease

 

Clintwood, VA

 

Northeast/Mid-Con

 

Lease

 

Midland, TX

 

Southwest

 

Lease

 

Cotulla, TX

 

Southwest

 

Own

 

Williston, ND

 

Rocky Mountains

 

Own

 

Bossier City, LA

 

Northeast/Mid-Con

 

Lease

 

Oklahoma City, OK

 

Northeast/Mid-Con

 

Lease

 

LaSalle, CO

 

Rocky Mountains

 

Lease

 

Dickinson, ND

 

Rocky Mountains

 

Lease

 

Eunice, NM

 

Southwest

 

Lease

 

Elk City, OK

 

Northeast/Mid-Con

 

Own

 

Powell, WY

 

Rocky Mountains

 

Lease

 

Houston, TX

 

Corporate Administrative Headquarters

 

Lease

 

Gillette, WY

 

Rocky Mountains

 

Own

 

Simpson District, WV

 

Northeast/Mid-Con

 

Lease

 

Kenedy, TX

 

Southwest

 

Lease

 

Gillette, WY

 

Rocky Mountains

 

Lease

 

Wellington, FL

 

Corporate Administrative Headquarters

 

Lease

 

Vernal, UT

 

Rocky Mountains

 

Lease

 

Odessa, TX

 

Southwest

 

Lease

 

Monahans, TX

 

Southwest

 

Lease

 

Tioga, PA

 

Northeast/Mid-Con

 

Lease

 

Casper, WY

 

Rocky Mountains

 

Lease

 

Sterling, CO

 

Rocky Mountains

 

Lease

 

Weatherford, TX

 

Southwest

 

Own

 

Rock Springs, WY

 

Rocky Mountains

 

Lease

 

Arnegard, ND

 

Rocky Mountains

 

Lease

 

We believe that our facilities are suitable for their present intended purposes and are adequate for our present and anticipated level of operations.

ITEM 3.  LEGAL PROCEEDINGS

We are a defendant in various legal actions arising in the normal course of business, the outcomes of which, in the opinion of management, neither individually nor in the aggregate are likely to result in a material adverse effect on our business, results of operations or financial condition.

There are no material pending legal proceedings, other than the ordinary routine litigation incidental to the business discussed above, to which we are a party of or of which any of our property is the subject. See Note 8. “Commitments, Contingencies and Off-Balance Sheet Arrangements” to our audited consolidated financial statements included elsewhere in this Form 10-K.

38

ITEM 4.  MINE SAFETY DISCLOSURES

Not Applicable.

39

PART II

ITEM 5.  MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Our common stock is quoted on the Nasdaq Global Select Market under the symbol “KLXE”.

On March 20, 2020, the last reported sale price of our common stock as reported by Nasdaq was $1.00 per share. As of such date, based on information provided to us by Computershare, our transfer agent, we had 1,151 registered holders, and because many of these shares are held by brokers and other institutions on behalf of the beneficial holders, we are unable to estimate the number of beneficial stockholders represented by these holders of record.

We have provided a line graph comparing the cumulative total stockholder return on our common stock between September 17, 2018 (our first trading day on the Nasdaq) and January 31, 2020 to the cumulative total returns of the S&P 500 Index and the Philadelphia Stock Exchange’s (“PHLX”) Oil Service Sector Index (“OSX”).

 

Picture 1

40

We do not currently intend to pay dividends. Our Board will establish our dividend policy based on our financial condition, results of operations and capital requirements, as well as applicable law, regulatory constraints, industry practice and other business considerations that our Board considers relevant. The terms of our debt agreements contain restrictions on our ability to pay dividends. The terms of agreements governing debt that we may incur in the future may also limit or prohibit dividend payments. Accordingly, we cannot assure you that we will either pay dividends in the future or continue to pay any dividend that we may commence in the future.

 

Unregistered Sales of Equity Securities and Use of Proceeds

Share Repurchases

($ in Millions, Except Shares and Per Share Data)

 

The following table presents the total number of shares of our common stock that we repurchased during the three months ended January 31, 2020:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Period

    

Total number of shares purchased1

    

Average price paid per share2

    

Total number of shares purchased as part of publicly announced plans or programs3

    

Approximate dollar value of shares that may yet be purchased under the plans or programs

 

November 1, 2019 - November 30, 2019

 

 

 —

 

$

 —

 

 

 —

 

$

48,859,603

 

December 1, 2019 - December 31, 2019

 

 

4,792

 

 

6.41

 

 

 —

 

 

48,859,603

 

January 1, 2020 - January 31, 2020

 

 

 —

 

 

 —

 

 

 —

 

 

48,859,603

 

Total

 

 

4,792

 

 

 

 

 

 —

 

 

 

 


(1)

Includes shares purchased from employees in connection with the settlement of income tax and related benefit withholding obligations arising from vesting of restricted stock grants under the Company’s Long-Term Incentive Plan.

(2)

The average price paid per share of common stock repurchased under the share repurchase program includes commissions paid to the brokers.

(3)

In August 2019, our board of directors authorized a share repurchase program for the repurchase of outstanding shares of the Company’s common stock having an aggregate purchase price up to $50.

 

 

ITEM 6.  SELECTED FINANCIAL DATA

 

In this section, dollar amounts are shown in millions, except for per share data or as otherwise specified.

The following table presents selected historical financial data for the periods indicated below. We derived the selected historical statements of earnings data for the years ended January 31, 2020, 2019 and 2018 and the balance sheet data as of January 31, 2020 and 2019 from our audited consolidated financial statements included elsewhere in this Form 10‑K. We derived the selected historical financial data as of January 31, 2018, 2017 and 2016 and for the fiscal years ended January 31, 2017 and 2016 from audited financial statements. We derived the selected historical financial data as of January 31, 2016 from KLX’s accounting records.

The historical statements of (loss) earnings for periods prior to September 14, 2018 reflect allocations of general corporate expenses from KLX, including, but not limited to, executive management, finance, legal, information technology, human resources, employee benefits administration, treasury, risk management and other shared services. The allocations were made on a direct usage basis when identifiable, with the remainder allocated on the basis of revenues generated, costs incurred, headcount or other measures. Our management considers these allocations to be a reasonable reflection of the utilization of services by, or the benefits provided to, KLX Energy Services. The allocations may not, however, reflect the expense we would have incurred as a stand‑alone public company for the periods presented. Actual costs that may have been incurred if we had been a stand‑alone company would depend on a number

41

of factors, including the chosen organizational structure, what functions were outsourced or performed by employees and strategic decisions made in areas such as information technology and infrastructure.

The financial statements for periods prior to the spin-off from KLX on September 14, 2018 included in this Form 10‑K may not necessarily reflect our financial position, results of operations and cash flows as if we had operated as a stand‑alone public company during all periods presented. Accordingly, our historical results should not be relied upon as an indicator of our future performance.

In presenting the financial data in conformity with GAAP, we are required to make estimates and assumptions that affect the amounts reported. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies,” included elsewhere in this Form 10‑K for a detailed discussion of the accounting policies that we believe require subjective and complex judgments that could potentially affect reported results.

The following selected historical financial and other data should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our audited consolidated financial statements and related notes included elsewhere in this Form 10‑K.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Year Ended

 

 

 

January 31,
2020

 

January 31,
2019

 

January 31,
2018

 

January 31,
2017

 

January 31,
2016

 

Statements of Earnings Data:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Service revenues

 

$

544.0

 

$

495.3

 

$

320.5

 

$

152.2

 

$

251.2

 

Cost of sales(1)

 

 

470.0

 

 

370.4

 

 

269.1

 

 

181.3

 

 

282.8

 

Selling, general and administrative(1)

 

 

100.0

 

 

100.4

 

 

73.4

 

 

60.1

 

 

78.5

 

Research and development costs

 

 

2.7

 

 

2.4

 

 

2.0

 

 

0.3

 

 

 —

 

Goodwill impairment charge(2)(3)

 

 

47.0

 

 

 —

 

 

 —

 

 

 —

 

 

310.4

 

Long-lived asset impairment charge(3)

 

 

 —

 

 

 —

 

 

 —

 

 

 —

 

 

329.8

 

Operating (loss) earnings

 

 

(75.7)

 

 

22.1

 

 

(24.0)

 

 

(89.5)

 

 

(750.3)

 

Interest expense, net

 

 

29.2

 

 

7.1

 

 

 —

 

 

 —

 

 

 —

 

(Loss) earnings before income taxes

 

 

(104.9)

 

 

15.0

 

 

(24.0)

 

 

(89.5)

 

 

(750.3)

 

Income tax (benefit) expense

 

 

(8.5)

 

 

0.6

 

 

0.1

 

 

0.1

 

 

0.1

 

Net (loss) earnings

 

$

(96.4)

 

$

14.4

 

$

(24.1)

 

$

(89.6)

 

$

(750.4)

 

Basic net (loss) earnings per share(4):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net (loss) earnings

 

$

(4.32)

 

$

0.72

 

$

(1.20)

 

$

(4.46)

 

$

(37.33)

 

Weighted average common shares

 

 

22.3

 

 

20.1

 

 

20.1

 

 

20.1

 

 

20.1

 

Diluted net (loss) earnings per share(4):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net (loss) earnings

 

$

(4.32)

 

$

0.71

 

$

(1.20)

 

$

(4.46)

 

$

(37.33)

 

Weighted average common shares

 

 

22.3

 

 

20.2

 

 

20.1

 

 

20.1

 

 

20.1

 

Balance Sheet Data (end of period):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Working capital

 

$

163.7

 

$

223.1

 

$

38.1

 

$

14.8

 

$

9.0

 

Goodwill, intangible and other assets, net

 

 

88.1

 

 

92.6

 

 

8.2

 

 

3.6

 

 

6.1

 

Total assets

 

 

623.4

 

 

672.8

 

 

273.8

 

 

205.0

 

 

234.8

 

Stockholders’ equity

 

 

312.2

 

 

340.7

 

 

224.6

 

 

178.0

 

 

192.1

 

Other Data:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Depreciation and amortization

 

 

64.1

 

 

41.5

 

 

33.5

 

 

36.2

 

 

46.6

 


(1)

For the year ended January 31, 2020, cost of sales and selling, general and administrative (“SG&A”) expense include $7.2 and $17.3, respectively, of costs primarily associated with cost rationalization and other costs, asset impairment costs and new product service line introduction costs as we rolled out large diameter coil tubing and flowback and testing services to additional geographic regions (collectively, “Costs as Defined”). For the year ended January 31, 2019, cost of sales and SG&A expense include $0.4 and $30.2, respectively, of costs primarily associated with the completion of the merger of the Aerospace Solutions business of KLX Inc. (“KLX”) with The Boeing Company, the spin-off of the company from our former parent, KLX, including $10.7 of non-cash compensation expense related to the acceleration of unvested shares held by our employees, the amendment of the ABL Facility due to the issuance of $250.0 of Notes and the acquisition of Motley (collectively, “Fiscal 2018 Costs

42

as Defined”). For the year ended January 31, 2018, cost of sales and SG&A expense include $0.3 and $3.3, respectively, of costs primarily associated with KLX’s strategic alternatives review and also a restructuring of the Eagle Ford region. For the year ended January 31, 2016, cost of sales and SG&A expense include $23.1 and $15.4, respectively, primarily associated with business separation and start-up costs such as costs related to the spin-off of KLX from its former parent, expansion initiatives, branding and IT implementation costs.

(2)

During the fiscal year ended January 31, 2020, we recorded a $47.0 goodwill impairment charge. The abrupt deterioration in industry conditions, which began in the third quarter and accelerated through the end of our fourth quarter of Fiscal 2019, was driven by a sharp decline in U.S. land rig count and an unprecedented decline in operating frac spreads from the second quarter through the end of 2019. The decline in E&P activity resulted in lower demand levels and lower current and expected revenues for our business, which led us to perform an interim goodwill impairment test in the third quarter. As a result, we reported a non-cash asset impairment charge of $47.0 in Fiscal 2019.

(3)

During the fiscal year ended January 31, 2016, we recorded a $640.2 goodwill and long-lived asset impairment charge. The rapid downturn in the oil and gas industry, including the nearly 75% decrease in the number of onshore drilling rigs and the resulting significant cutback in capital expenditures by our customers, resulted in a significant adverse change in the business climate, which indicated that our goodwill was impaired and our long-lived assets might not be recoverable. As a result, during the third quarter ended October 31, 2015, we performed an interim goodwill impairment test and a long-lived asset recoverability test and determined that our goodwill was fully impaired and recorded a pre-tax impairment charge of $310.4. Further, we utilized a combination of cost and market approaches to determine the fair value of our long-lived assets, resulting in an impairment charge of $177.8 related to identified intangibles and $152.0 related to property and equipment.

(4)

On September 14, 2018, KLX distributed to its stockholders of record as of the close of business on September 3, 2018, 0.4 shares of KLX Energy Services common stock for every 1.0 share of KLX common stock held as of the record date. January 31, 2018, 2017 and 2016 basic and diluted net loss per common share and the average number of common shares outstanding were calculated using the number of KLX Energy Services common shares outstanding immediately following the distribution. See Note 10 to our audited consolidated financial statements included elsewhere in this Form 10-K.

43

ITEM 7.  MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

You should read the following discussion of our results of operations and financial condition together with our audited consolidated financial statements and accompanying notes included elsewhere in this Form 10-K as well as the discussion in “Item 1. Business.” This discussion contains forward-looking statements that involve risks and uncertainties. The forward-looking statements are not historical facts, but rather are based on our current expectations, estimates, assumptions and projections about our industry, business and future financial results. Our actual results could differ materially from the results contemplated by these forward-looking statements due to a number of factors, including those we discuss in “Item 1A. Risk Factors” and “Cautionary Statement Regarding Forward-Looking Statements.”

Our consolidated financial statements, which we discuss below, reflect our historical financial condition, results of operations and cash flows. The financial information for periods prior to the spin-off from KLX on September 14, 2018 included in this Form 10-K may not necessarily reflect what our financial condition, results of operations or cash flows would have been had we been operated as a separate, independent entity during all periods presented. In this section, dollar amounts are shown in millions, except for per share and per barrel amounts or as otherwise specified.

Company Overview

We are a leading provider of completion, intervention and production services and products (our “product service lines” or “PSLs”) to the major onshore oil and gas producing regions of the United States. We offer a range of differentiated, complementary technical services and related tools and equipment in challenging environments that provide “mission critical” solutions for our customers throughout the life cycle of the well.

 

We serve many of the leading companies engaged in the exploration and development of North American onshore conventional and unconventional oil and natural gas reserves. Our customers are primarily independent major oil and gas companies. We actively support these customer operations from over 35 principal service facilities located in the key major shale basins. We operate in three segments on a geographic basis, including the Southwest Region (the Permian Basin and the Eagle Ford), the Rocky Mountains Region (the Bakken, Williston, DJ, Uinta, Powder River, Piceance and Niobrara basins) and the Northeast/Mid-Con Region (the Marcellus and Utica as well as the Mid-Continent STACK and SCOOP and Haynesville). Our revenues, operating profits and identifiable assets are primarily attributable to these three reportable geographic segments. However, while we manage our business based upon these regional groupings, our assets and our technical personnel are deployed on a dynamic basis across all of our service facilities to optimize utilization and profitability.

 

We work with our customers to provide engineered solutions across the entire lifecycle of the well, by streamlining operations, reducing non-productive time and developing cost effective solutions and customized tools for our customers’ most challenging service needs, which include technically complex unconventional wells requiring extended reach horizontal laterals with greater completion intensity per well. We believe future revenue growth opportunities will continue to be driven by increases in the number of new customers served and the breadth of services we offer to existing and prospective customers.

 

We offer a variety of targeted services that are differentiated by the technical competence and experience of our field service engineers and their deployment of a broad portfolio of specialized tools and equipment. Our innovative and adaptive approach to proprietary tool design has been employed by our in-house research and development (“R&D”) organization and, in selected instances, by our technology partners to develop tools covered by 20 patents and 18 U.S. and foreign pending patent applications. Our technology partners include manufacturing and engineering companies that produce tools, which we design and utilize in our service offerings.

 

We utilize contract manufacturers to produce our products, which, in many cases, our engineers have developed from input and requests from our customers and customer-facing managers, thereby maintaining the integrity of our intellectual property while avoiding manufacturing startup and maintenance costs. We have found that doing so leverages our technical strengths as well as those of our technology partners. These PSLs are modest in cost to the

44

customer relative to other well construction expenditures but have a high cost of failure and are, therefore, “mission critical” to our customers’ outcomes. We believe our customers have come to depend on our decades of combined field experience to execute on some of the most challenging problems they face. We believe we are well positioned as a company to service customers when they are drilling and completing complex wells and remediating older legacy wells.

 

KLX Energy Services was initially formed from the combination and integration of seven private oilfield service companies acquired over the 2013 through 2014 time period. Each of the acquired businesses was regional in nature and brought one or two specific service capabilities to KLX Energy Services. Once the acquisitions were completed, we undertook a comprehensive integration of these businesses, to align our services, our people and our assets across all the geographic regions where we maintain a presence. We established a matrix management organizational structure, where each regional manager has the resources to provide a complete suite of services, supported by technical experts in our primary service categories. In November 2018, we expanded our completion and intervention service offerings through the acquisition of Motley Services, LLC (“Motley”), a premier provider of large diameter coiled tubing services, further enhancing our completion tools business. We successfully completed the integration of the Motley business during Fiscal 2018. On March 15, 2019, the Company acquired Tecton Energy Services (“Tecton”), a leading provider of flowback, drill-out and production testing services, operating primarily in the greater Rocky Mountains. On March 19, 2019, the Company acquired Red Bone Services LLC (“Red Bone”), a premier provider of oilfield services primarily in the Mid-Continent, providing fishing, non-frac high pressure pumping, thru-tubing and certain other services. We successfully completed the integration of the Red Bone business during Fiscal 2019. We have endeavored to create a “next generation” oilfield services company in terms of management controls, processes and operating metrics and have driven these processes down through the operating management structure in every region, which we believe differentiates us from many of our competitors. This allows us to offer our customers in all of our geographic regions discrete, comprehensive and differentiated services that leverage both the technical expertise of our skilled engineers and our in-house R&D team.

 

Following the acquisition of Motley, we have invested in seven additional large diameter coil tubing spreads which we believe will allow us to gain a greater share of customer spend by pulling through the Company’s broad range of asset light services.

 

We invest in innovative technology and equipment designed for modern production techniques that increase efficiencies and production for our customers. North American unconventional onshore wells are increasingly characterized by extended lateral lengths, tighter spacing between hydraulic fracturing stages, increased cluster density and heightened proppant loads. Drilling and completion activities for wells in unconventional resource plays are extremely complex, and downhole challenges and operating costs increase as the complexity and lateral length of these wells increase. For these reasons, E&P companies with complex wells increasingly prefer service providers with the scale and resources to deliver best-in-class solutions that evolve in real time with the technology used for extraction. We believe we offer best-in-class service execution at the wellsite and innovative downhole technologies, positioning us to benefit from our ability to service the most technically complex wells where the potential for increased operating leverage is high due to the large number of stages per well in addition to customer focus on execution rather than price. We have been awarded 20 U.S. patents and have 18 U.S. and foreign pending patent applications, which we believe differentiates us from our regional competition and also allows us to deliver more focused service and better outcomes in our specialized services than larger national competitors who do not discretely dedicate their resources to the services we provide.

 

Our business strategy seeks to generate attractive returns on capital through the provision of differentiated services and the prudent application of our cash flow to select targeted opportunities, with the potential to deliver high returns that we believe offer superior margins over the long-term and short payback periods. Our services generally require less expensive equipment, which is also less expensive to maintain, and fewer people than many other oilfield service activities. In addition to the superior margin potential of our differentiated services, we believe the rising level of completion intensity in our core operating areas contributes to improved margins and returns on services provided for those wells. As part of our returns-focused approach to capital spending, we are focused on maintaining a capital efficient program with respect to the development of new products. We support our existing asset base with targeted investments in R&D, which we believe allows us to maintain a technical advantage over our competitors providing similar services using standard equipment.

45

Demand for services in the oil and natural gas industry is cyclical and subject to sudden and significant volatility. For example, the oilfield service industry experienced an abrupt deterioration in demand during the second half of 2019, principally due to the E&P companies’ intense focus on capital discipline and free cash flow generation and customer budget exhaustion, which led to a sharp decline in U.S. land rig count and an unprecedented decline in operating frac spreads from the second quarter through the end of 2019. These downturns placed unprecedented pressure on both our customers and competitors.

 

As a result of the ongoing decrease in global demand for oil and gas resulting from the recent COVID-19 outbreaks, in March 2020, members of OPEC and Russia considered extending their agreed oil production cuts and making additional oil production cuts. Negotiations were unsuccessful, and Saudi Arabia announced an immediate significant reduction in its oil export prices, and Russia announced that all agreed oil production cuts between Russia and OPEC members would expire on April 1, 2020. Oil and natural gas prices declined sharply immediately following these announcements and have further declined to levels as low as approximately $21 per barrel.

 

Oil and natural gas prices are expected to continue to be volatile as a result of the near term production increases and the ongoing COVID-19 outbreaks and as changes in oil and natural gas inventories, industry demand and global and national economic performance are reported. Significant factors that are likely to affect commodity prices in current and future periods include, but are not limited to, the extent and duration of price reductions and increased production by OPEC members and other oil exporting nations; the effect of U.S. energy, monetary and trade policies, U.S. and global economic conditions, U.S. and global political and economic developments, including the outcome of the U.S. presidential election and resulting energy and environmental policies, the impact of the ongoing COVID-19 outbreaks and conditions in the U.S. oil and gas industry and the resulting demand and pricing for domestic land oilfield services.

 

The reduction in oil prices to current levels and the ongoing effects of the global COVID-19 outbreaks will likely result in a global recession, with the possibility of numerous bankruptcies of E&P companies and oilfield services companies during 2020 and a significant decline in demand and prices for oilfield services during 2020. We have taken, and are continuing to take, steps to reduce costs, including reductions in capital expenditures, as well as other workforce rightsizing and ongoing cost initiatives.

 

Despite very difficult industry conditions during the second half of 2019, we were able to execute our strategy to expand our key product service lines, including coil tubing spreads, flowback and testing, and we expanded our intervention capabilities in the Mid-Con, Northeast and South Texas. We believe these actions will allow us to increase our share of customer spend as we deploy coil tubing spreads and continue to pull through asset light services such as flowback, thru-tubing and pressure control services, while leveraging our recently enhanced cost structure. 

 

We remain focused on serving the needs of our customers by providing a broad portfolio of product service lines across all major basins, while preserving a solid balance sheet, maintaining sufficient operating liquidity and prudently managing our capital expenditures.

 

We believe we have positioned our company to operate successfully as a standalone company as a result of the numerous initiatives we undertook during the integration of the seven businesses acquired while we were part of KLX Inc. (the “Former Parent” or “KLX”). We believe our operating cost structure is now materially lower than during the historical financial reporting periods and that there is greater flexibility to respond to changing industry conditions. We improved our cost structure by centralizing a number of common functions, as evidenced by our positive cash provided by operating activities in Fiscal 2019. The implementation of integrated, company-wide management information systems and processes provide more transparency to current operating performance and trends within each market where we compete and help us more acutely scale our cost structure and pricing strategies on a market-by-market basis. We believe our ability to differentiate ourselves on the basis of quality provides an opportunity for us to gain market share and increase our share of business with existing customers.

 

We believe we have strong management systems in place, which will allow us to manage our operating resources and associated expenses relative to market conditions. We believe our services often generate margins superior to our competitors based upon the differential quality of our performance, and that these margins can contribute to free

46

cash flow generation. The required investment in our business includes both working capital (principally for account receivables growth tied to increasing revenues) and capital expenditures for both maintenance of existing assets and growth. Our required maintenance capital expenditures tend to be lower than other oilfield service providers due to the generally asset-lite nature of our services, the average age of our assets and our ability to charge back a portion of asset maintenance to customers for a number of our assets.

 

The Spin‑off

 

On September 14, 2018, we completed our spin-off from KLX and became an independent, publicly-traded company. In connection with the consummation of the spin-off, KLX Energy Services entered into a number of agreements with KLX. All services under the transition services agreement with KLX were terminated prior to October 31, 2018, and amounts under such agreement were not material for the year ended January 31, 2019. In addition, our undrawn $100.0 asset-based revolving credit facility (“ABL Facility”) is available for borrowing for working capital and other general corporate purposes. The approximately $60.0 availability under the ABL Facility is tied to the aggregate amount of our accounts receivable and inventory that satisfy specified criteria and is subject to further limitation based upon our maintaining a minimum fixed charge coverage ratio. We issued $250.0 principal amount of 11.5% senior secured notes due 2025 (the “Notes”) and, depending on market conditions, we may incur other indebtedness in the future to make additional acquisitions and/or provide for additional cash on the balance sheet, which could be used for future acquisitions.

 

For the years ended January 31, 2019 and 2018, selling, general and administrative (“SG&A”) expense included allocations of general corporate expenses from KLX for periods through September 14, 2018, the date of the spin-off. The historical consolidated statements of (loss) earnings for periods prior to the spin-off reflect allocations of general corporate expenses from KLX, including, but not limited to, executive management, finance, legal, information technology, human resources, employee benefits administration, treasury, risk management, procurement and other shared services. The allocations were made on a direct usage basis when identifiable, with the remainder allocated on the basis of revenues generated, costs incurred, headcount or other measures. Our management considers these allocations to be a reasonable reflection of the utilization of services by, or the benefits provided to, KLX Energy Services during such periods. The allocations may not, however, reflect the expense we would have incurred as a stand-alone company for the periods presented. Actual costs that may have been incurred if we had been a stand-alone company would depend on a number of factors, including the chosen organizational structure, what functions were outsourced or performed by employees and strategic decisions made in areas such as information technology and infrastructure. See Note 1. “Description of Business and Summary of Significant Accounting Policies” to our audited consolidated financial statements included elsewhere in this Form 10-K for a description of the costs allocated, the methods of allocation, the reasons for the allocations and how our actual costs may differ from the amounts allocated under the ownership of KLX.

 

Key Financial Performance Indicators

We recognize the highly cyclical nature of our business and the need for metrics to (1) best measure the trends in our operations and (2) provide baselines and targets to assess the performance of our managers.

 

The metrics we regularly monitor within each of our geographic reporting regions include:

 

·

Variable cost by service;

·

Asset utilization by service; and

·

Revenue growth by service.

 

The measures we believe most effective to monitor and consider when rewarding management performance include:

 

·

Revenue growth rate;

·

EBITDA growth rate;

·

EBITDA margin;

·

Return on invested capital;

47

·

Cash flow generation after investments in the business; and

·

Effectiveness of our health, safety and environmental practices.

 

Our experience has shown us that measuring our performance is most meaningful when compared against our peers on a relative basis. Our compensation committee engages its own compensation consultant to recommend performance metrics and targets for our employees.

 

Year Ended January 31, 2020 Compared to Year Ended January 31, 2019

 

The following is a summary of revenues by segment:

 

 

 

 

 

 

 

 

 

 

 

 

 

Year Ended

 

 

 

 

 

    

January 31, 

    

January 31, 

    

Percent

 

 

2020

 

2019

 

Change

Southwest

 

$

177.9

 

$

186.2

 

 

(4.5)

%

Rocky Mountains

 

 

216.4

 

 

179.7

 

 

20.4

%

Northeast/Mid-Con

 

 

149.7

 

 

129.4

 

 

15.7

%

Total revenues

 

$

544.0

 

$

495.3

 

 

9.8

%

 

Revenues for the year ended January 31, 2020 were $544.0, an increase of $48.7, or 9.8%, as compared to the prior year. Revenue growth reflects the addition of coil tubing, flow back and testing services and intervention product service lines during Fiscal 2019, offset by the impact from the aforementioned second half deterioration in industry conditions. Revenues in the first half of Fiscal 2019 increased by approximately $82.5 as compared with the same period in the prior year; revenues in the second half of Fiscal 2019 were approximately $33.8 lower than the same period in the prior year. On a product line basis, completion and intervention services revenues increased approximately 15.3% and 8.9%, respectively, while production revenues declined approximately 3.4%.

 

Cost of sales for the year ended January 31, 2020 was $470.0, or 86.4% of sales, including $7.2 of Costs as Defined, as compared to the prior year period of $370.4, or 74.8% of sales. Excluding the $7.2 of Costs as Defined ($0.4 in the prior year period), cost of sales was $462.8, or 85.1% of revenues ($370.0, or 74.7% of revenues, in the prior year period), and increased by $92.8 as compared to the prior year period. Cost of sales increased primarily due to the under-absorption of fixed costs as a result of the abrupt deterioration in demand during the second half of 2019 as well as the startup costs associated with the roll out of flowback and testing services and costs to support the roll out of the coiled tubing PSL in both the Northeast/Mid-Con and Rocky Mountains segments.

 

SG&A expenses for the year ended January 31, 2020, inclusive of Costs as Defined of $17.3, were $100.0, or 18.4% of revenues, as compared with $100.4, or 20.3% of revenues (which included $30.2 of spin-off costs and expenses), in the prior year period. Excluding the Costs as Defined in the current year period ($30.2 in the prior year period), SG&A expenses were $82.7, or 15.2% of revenues, as compared with $70.2, or 14.2% of revenues, in the prior year period. Research and development costs were $2.7 in the current year period as compared to $2.4 in the prior year period, reflecting our continued focus on in-house research and development to deploy new specialized and proprietary tools and equipment.

 

As previously described above and in Note 4 to our audited consolidated financial statements included elsewhere in this Form 10-K, we recorded $47.0 of goodwill impairment charges during the six months ended January 31, 2020. Approximately $22.4 of this charge was attributable to goodwill in the Southwest segment and $24.6 was attributable to goodwill in the Northeast/Mid-Con segment.

 

Operating loss and operating margin, including Costs as Defined of $24.5 and the goodwill impairment charges of $47.0, were $(75.7) and (13.9)%, respectively. Exclusive of the $24.5 of Costs as Defined ($30.6 in the prior year period) and the $47.0 goodwill impairment charge, current period operating loss was $(4.2) as compared to operating earnings of $52.7 in the prior year period. As previously discussed, operating results were negatively impacted by a number of customers suspending operations for the balance of the year in the Rocky Mountains and Northeast/Mid-Con segments, increased pricing pressure, particularly from natural gas customers in the Northeast/Mid-Con segment, low utilization of wireline assets in the Southwest segment due to our decision not to deploy these assets at pricing offered by

48

our competitors, startup costs associated with the roll out of flowback and testing services and costs to support the roll out of the coiled tubing PSL in both the Northeast/Mid-Con and Rocky Mountains segments.

 

Income tax benefit was $8.5 for the year ended January 31, 2020, as compared to $0.6 of income tax expense in the prior year period, reflecting the effective tax rate of approximately 8.1% resulting primarily from the benefit recorded in the fourth quarter of Fiscal 2019. The income tax benefit relates to the reduction of the valuation allowance relative to acquired Red Bone and Tecton’s deferred tax liabilities via purchase accounting of approximately $8.9. The benefit is partially offset by current state tax expense of $0.4. Aside from a negligible amount of state and local taxes, there was no income tax expense in the prior year due to the fact that we had established a full valuation allowance against our net deferred tax asset.

 

Net loss for the year ended January 31, 2020 was $(96.4) as compared to net earnings of $14.4 in the prior year period for the reasons mentioned above as well as $29.2 of interest expense ($7.1 in the prior year period).

 

Segment Results

The following is a summary of operating (loss) earnings by segment:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Year Ended

 

 

 

 

 

    

January 31, 

    

January 31, 

    

Percent

 

 

2020

 

2019

 

Change

Southwest

 

$

(54.3)

 

$

3.2

 

 

nm

 

Rocky Mountains

 

 

10.1

 

 

5.5

 

 

83.6

%

Northeast/Mid-Con

 

 

(31.5)

 

 

13.4

 

 

(335.1)

%

Total operating (loss) earnings

 

$

(75.7)

 

$

22.1

 

 

(442.5)

%

 

For the year ended January 31, 2020, Rocky Mountains segment revenues of $216.4 increased by 20.4%, driven by increases in completions, intervention and production of 33.6%, 8.8% and 4.8%, respectively. The Rocky Mountains segment experienced an increase in the number of customers served, increased activity across substantially all product lines, improved adoption rates of recently introduced proprietary tools, including the HydroPullTM tool in combination with our proprietary motor bearing assembly, and dissolvable plugs, as well as approximately $23.1 of growth from the addition of Tecton flowback and testing revenues. The revenue increases were partially offset by a number of customers suspending operations for the latter part of the year due to budget exhaustion and E&P companies’ intense focus on capital discipline and free cash flow generation. Operating earnings and operating margin were approximately $10.1 and 4.7%, increases of 83.6% and 160 basis points, respectively, as compared to the prior year period.

 

For the year ended January 31, 2020, Northeast/Mid-Con segment revenues of $149.7 increased by approximately 15.7% driven by increases in completions and intervention of 9.1% and 46.6%, respectively, partially offset by a decrease in production of 0.6%. The Northeast/Mid-Con segment experienced an increase in the number of customers served, improved adoption rates of proprietary tools and the March 2019 acquisition of Red Bone. These increases were offset by a number of customers suspending operations for the latter part of the year due to budget exhaustion and E&P companies’ intense focus on capital discipline and free cash flow generation, along with lower activity levels among certain other customers, particularly from natural gas customers. The Northeast/Mid-Con segment has the highest exposure, as a percentage of revenues, to natural gas customers. Natural gas rigs declined by almost 43% as compared with February 2019. As a result of the aforementioned industry conditions and associated goodwill impairment charge of $24.6, as well as unabsorbed fixed costs related to the Red Bone acquisition and the aforementioned subsequent abrupt decline in demand, operating loss and operating margin for the current period were $(31.5) and (21.0)%, respectively.

 

For the year ended January 31, 2020, Southwest segment revenues of $177.9 decreased 4.5% primarily due to decreases in intervention and production of 18.9% and 21.3%, respectively, partially offset by an increase in completions of 4.5%. The decrease in Southwest segment revenues was primarily driven by lower overall activity levels due to budget exhaustion and E&P companies’ intense focus on capital discipline and free cash flow generation and a decline in wireline revenues as we continued to warm stack the vast majority of our Permian based wireline assets in the weak demand and pricing environment. The decreases were partially offset by the addition of revenues from the Motley

49

acquisition. The Southwest segment also incurred costs to support the rollout of the coiled tubing PSL in both the Northeast/Mid-Con and the Rocky Mountains segments. Primarily as a result of the factors described above, as well as the goodwill impairment attributable to the Southwest segment of $22.4, operating loss was $(54.3) for the year ended January 31, 2020.

 

Year Ended January 31, 2019 Compared to Year Ended January 31, 2018

The following is a summary of revenues by segment:

 

 

 

 

 

 

 

 

 

 

 

 

 

Year Ended

 

 

 

 

 

    

January 31, 

    

January 31, 

    

Percent

 

 

2019

 

2018

 

Change

Southwest

 

$

186.2

 

$

109.5

 

 

70.0

%

Rocky Mountains

 

 

179.7

 

 

127.0

 

 

41.5

%

Northeast/Mid-Con

 

 

129.4

 

 

84.0

 

 

54.0

%

Total revenues

 

$

495.3

 

$

320.5

 

 

54.5

%

 

Fiscal 2018 revenues were $495.3, an increase of $174.8, or 54.5%, as compared with the same period of the prior year. Revenue growth was driven by a 70.0% increase in Southwest revenues, a 41.5% increase in Rocky Mountains revenues and a 54.0% increase in Northeast/Mid-Con revenues, reflecting a double-digit percentage increase in the number of new customers and a significant increase in the breadth of services provided to existing customers along with the contribution of the Motley acquisition in the Southwest. Year-over-year product line revenue growth for completion, production and intervention services was 77.2%, 50.4% and 21.0%, respectively.

 

Cost of sales for Fiscal 2018, including $0.4 of Fiscal 2018 Costs as Defined, was $370.4, or 74.8% of sales, as compared to $269.1, or 84.0% of sales, in the prior year. Cost of sales as a percentage of revenues improved by approximately 920 basis points, due to substantially improved results at all three segments of our business resulting from improved market conditions, increased sales of higher margin PSLs and operating leverage.

 

SG&A expense during Fiscal 2018 was $100.4, or 20.3% of revenues, as compared with $73.4, or 22.9% of revenues, in the prior year. SG&A, as a percentage of revenues, decreased by approximately 260 basis points as compared with the prior year primarily due to increased operating leverage as the 54.5% increase in revenues outpaced the 36.8% increase in SG&A. Excluding the $30.2 of Fiscal 2018 Costs as Defined ($3.3 in the prior year period), SG&A was $70.2, or 14.2% of revenues, and as a percentage of revenues, improved approximately 770 basis points for Fiscal 2018 as compared with the prior year primarily due to the increased operating leverage and a $4.0 gain on the divestiture of certain assets in the Northeast/Mid-Con segment, which was partially offset by new product introduction costs and Motley integration costs. Research and development costs for Fiscal 2018 were $2.4 as compared to $2.0 in the prior year, reflecting our continued focus on in-house research and development to deploy new specialized and proprietary tools.

 

Operating earnings were $22.1, including the $30.6 of Fiscal 2018 Costs as Defined discussed above, as compared to a loss of $(24.0) in the prior year. Exclusive of Fiscal 2018 Costs as Defined, operating earnings of $52.7 for the year ended January 31, 2019 increased by $73.1 reflecting a higher level of activity by our customers throughout our geographic regions and incremental operating leverage. The continued recovery in the major oil and gas producing basins of the onshore U.S. market has resulted in increased demand for our products and services. Additionally, we believe incremental growth has been driven by differentiation in our products and services due to successful R&D initiatives and the quality and depth of our personnel.

 

Income tax expense for Fiscal 2018 was $0.6 reflecting the effective tax rate of approximately 4% resulting primarily from state and local taxes. The statutory tax rate of 21% offset by a benefit from the Company’s deferred tax assets resulted in no additional tax expense. Aside from a negligible amount of state and local taxes, there was no income tax expense in the prior year due to the fact that we had established a full valuation allowance against our net deferred tax asset.

 

Net earnings were $14.4 for Fiscal 2018 as compared to a net loss of $(24.1) in the prior year. Net earnings

50

were favorably impacted by the improvements in pricing and activity driven by the overall improvement in the oil and gas sector offset by the $30.6 of aforementioned Fiscal 2018 Costs as Defined.

 

Segment Results

The following is a summary of operating earnings (loss) by segment:

 

 

 

 

 

 

 

 

 

 

 

 

 

Year Ended

 

 

 

 

 

    

January 31, 

    

January 31, 

    

Percent

 

 

2019

 

2018

 

Change

Southwest

 

$

3.2

 

$

(12.8)

 

 

125.0

%

Rocky Mountains

 

 

5.5

 

 

(0.8)

 

 

787.5

%

Northeast/Mid-Con

 

 

13.4

 

 

(10.4)

 

 

228.8

%

Total operating earnings (loss)(1)

 

$

22.1

 

$

(24.0)

 

 

192.1

%


(1)

During the year ended January 31, 2019, we incurred approximately $30.6 of Fiscal 2018 Costs as Defined ($3.6 in the prior year).

 

For Fiscal 2018, Southwest revenues of $186.2 increased by $76.7, or 70.0%, as compared to the prior year, driven primarily by significant increases in both the number of active customers and the breadth of services provided to existing customers. The Southwest also benefited from the newly introduced PSLs, including the downhole product solutions PSL, and the addition of Motley’s large diameter coiled tubing business. Revenues from completion, production and intervention activities increased approximately 87.3%, 66.5% and 36.9%, respectively. Southwest operating earnings of $3.2 improved by $16.0, including the negative impact of $10.2 of Fiscal 2018 Costs as Defined ($1.2 in the prior year), reflecting the increased demand for our products and services and operating leverage inherent in our cost and operating structure.

 

For Fiscal 2018, Rocky Mountains revenues of $179.7 increased by $52.7, or 41.5%, driven primarily by significant increases in both the number of active customers and the breadth of services provided to existing customers. Revenues from completion and production activities increased approximately 75.5% and 40.2%, respectively. Rocky Mountains operating earnings of $5.5 improved by $6.3, including the negative impact of $11.9 of Fiscal 2018 Costs as Defined ($1.4 in the prior year), reflecting the increased demand for our products and services and operating leverage inherent in our cost and operating structure.

 

For Fiscal 2018, Northeast/Mid-Con revenues of $129.4 increased by $45.4, or 54.0%, also driven primarily by significant increases in both the number of active customers and the breadth of services provided to existing customers. Revenues from completion, production and intervention activities increased approximately 63.4%, 53.9% and 37.9%, respectively. Northeast/Mid-Con operating earnings of $13.4 improved by $23.8, including the $4.0 gain on the sale of assets no longer deployed and the negative impact of $8.5 of Fiscal 2018 Costs as Defined ($1.0 in the prior year), reflecting the increased demand for our products and services and operating leverage inherent in our cost and operating structure.

 

Liquidity and Capital Resources

Current Financial Condition

Cash on hand at January 31, 2020 decreased by $40.3 as compared with cash on hand at January 31, 2019 primarily as a result of $70.8 of capital expenditures and $27.6 related to the acquisition of Red Bone and Tecton, offset by cash flows from operating activities of $58.1. Our liquidity requirements consist of working capital needs and ongoing capital expenditure requirements. Our primary requirements for working capital are directly related to the level of our operations. Our pre-spin-off sources of liquidity historically were from advances from KLX and cash flow from operations.

51

Working Capital

Working capital as of January 31, 2020 was $163.7, a decrease of $59.4 as compared with working capital at January 31, 2019. As of January 31, 2020, total current assets decreased by $79.8 and total current liabilities decreased by $20.4. The decrease in current assets was primarily related to a decrease in accounts receivable of $40.4 and a decrease in cash and cash equivalents of $40.3. The decrease in total current liabilities was primarily due to a decrease in accounts payable of $15.9.

Working capital as of January 31, 2019 was $223.1, an increase of $185.0 as compared with working capital at January 31, 2018. As of January 31, 2019, total current assets increased by $222.2 and total current liabilities increased by $37.2. The increase in current assets was primarily related to an increase in cash of $163.8. The increase in total current liabilities was primarily due to an increase in accounts payable of $15.5 and accrued liabilities of $14.5.

Cash Flows

Net cash flows provided by operating activities was $58.1 for the year ended January 31, 2020 as compared to $62.0 in the prior year, primarily reflecting a $110.8 decrease in net earnings adjusted for non-cash depreciation and amortization of $64.1 ($41.5 in the prior year), impairment charge of $47.0 (none in the prior year) and a decrease in accounts receivable of $39.9 ($23.2 increase in the prior year). Net cash flows used in investing activities was $97.7 for the year ended January 31, 2020 as compared to $214.1 in the prior year, and were primarily related to capital expenditures of $70.8 ($84.0 in the prior year) and the acquisition of Red Bone and Tecton for $27.6 ($140.0 in the prior year related to the acquisition of Motley). Net cash flows used in financing activities was $0.7 for the year ended January 31, 2020, as compared to net cash flows provided by financing activities of $315.9 in the prior year, and primarily reflect $1.5 cash proceeds from restricted stock issuance offset by $1.2 of common stock repurchased and $1.0 for restricted stock cancelled for taxes (none in the prior year).

Net cash flows provided by operating activities was $62.0 for the year ended January 31, 2019 as compared to net cash used in operating activities of $9.4 in the prior year, primarily reflecting a $38.5 increase in net earnings adjusted by depreciation and amortization of $41.5 ($33.5 in the prior year) and a $17.5 increase in accounts payable and accrued liabilities ($18.4 increase in the prior year) offset by a $23.2 increase in accounts receivable ($43.0 increase in the prior year). Net cash used in investing activities was $214.1 for the year ended January 31, 2019, as compared to $48.8 in the prior year, and were primarily related to capital expenditures of $84.0 ($49.4 in the prior year), including $5.2 in deposits on capital expenditures to be received in 2019, and the acquisition of Motley for $140.0. Net cash flows provided by financing activities was $315.9 for the year ended January 31, 2019, as compared to $58.2 in the prior year, and primarily reflect $250.0 of proceeds from long-term debt and $75.2 of aggregate pre-spin-off net funding from our Former Parent ($58.2 in the prior year), offset by $9.3 of debt offering costs.

Capital Spending

Our capital expenditures were $70.8 (net of $9.8 in deposits accounted for as capital expenditures in a prior period), $84.0 (including $5.2 in deposits on equipment) and $49.4 during the years ended January 31, 2020, 2019 and 2018, respectively. We currently expect to incur approximately $25 to $30 in capital expenditures for the year ending January 31, 2021, based on current industry conditions and our recent significant investments in capital expenditures over the past several years.

The nature of our capital expenditures is comprised of a base level of investment required to support our current operations and amounts related to growth and company initiatives. Capital expenditures for growth and company initiatives are discretionary. We continually evaluate our capital expenditures, and the amount we ultimately spend will depend on a number of factors, including expected industry activity levels and company initiatives. We expect to fund future capital expenditures from cash on hand and cash flow from operations. We have funds available from our ABL Facility (under which the amount of availability depends in part on a borrowing base tied to the aggregate amount of our accounts receivable and inventory satisfying specified criteria and our compliance with a minimum fixed charge coverage ratio).

52

Our ability to satisfy our liquidity requirements depends on our future operating performance, which is affected by prevailing economic conditions, the level of drilling, completion, intervention and production activity for North American onshore oil and natural gas resources, and financial and business and other factors, many of which are beyond our control. We believe that our cash flows, together with cash on hand, will provide us with the ability to fund our operations and make planned capital expenditures for at least the next 12 months. We have funds available under our ABL Facility (under which the amount of availability depends in part on a borrowing base tied to the aggregate amount of our accounts receivable and inventory satisfying specified criteria and our compliance with a minimum fixed charge coverage ratio).

Financing Arrangements

We entered into a $100.0 ABL Facility on August 10, 2018. The ABL Facility became effective on September 14, 2018, the date of the spin-off, and is scheduled to mature in September 2023. Borrowings under the ABL Facility bear interest at a rate equal to the London interbank offered rate (“LIBOR”) (as defined in the ABL Facility) plus the applicable margin (as defined). Availability under the ABL Facility is tied to a borrowing base formula and the ABL Facility has no maintenance financial covenants as long as we maintain a minimum level of borrowing availability. The ABL Facility is secured by, among other things, a first priority lien on our accounts receivable and inventory and contains customary conditions precedent to borrowing and affirmative and negative covenants, all of which were met as of January 31, 2020. No amounts were outstanding under the ABL Facility as of January 31, 2020. The effective interest rate under the ABL Facility would have been approximately 3.8% on January 31, 2020.

In conjunction with the acquisition of Motley, we issued $250.0 of Notes due 2025 offered pursuant to Rule 144A under the Securities Act and to certain non-U.S. persons outside the United States in compliance with Regulation S under the Securities Act. On a net basis, after taking into consideration the debt issue costs for the Notes, total net proceeds were $242.0, which a portion was used to acquire Motley, and the balance is available for general corporate purposes including potential acquisitions.

We believe our cash at January 31, 2020 of $123.5 along with $60.0 of availability under our $100 undrawn ABL Facility, provide us with the ability to fund our operations, make planned capital expenditures, repurchase our debt or equity securities, meet our debt service obligations and provide funding for potential future acquisitions. During periods in which our fixed charge coverage ratio as determined under the ABL Facility is not at least 1:1 for the trailing four quarters for which financial statements have been delivered, the amount of availability under the ABL facility will be reduced by the greater of $10.0 or 15% of the borrowing base.

Contractual Obligations

The following table reflects our contractual obligations and commercial commitments as of January 31, 2020. Commercial commitments include lines of credit, guarantees and other potential cash outflows resulting from a contingent event that requires performance by us or our subsidiaries pursuant to a funding commitment.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Year Ending January 31,

Contractual Obligations

    

2021

    

2022

    

2023

    

2024

    

2025

    

Thereafter

    

Total

Long-term debt and other non-current liabilities

 

$

0.5

 

$

0.2

 

$

0.2

 

$

0.2

 

$

0.2

 

$

252.1

 

$

253.4

Operating leases

 

 

27.4

 

 

17.0

 

 

10.2

 

 

8.6

 

 

6.6

 

 

2.4

 

 

72.2

Future interest and fees on outstanding debt (1)

 

 

29.3

 

 

29.3

 

 

29.3

 

 

29.1

 

 

28.8

 

 

28.7

 

 

174.5

Total

 

$

57.2

 

$

46.5

 

$

39.7

 

$

37.9

 

$

35.6

 

$

283.2

 

$

500.1

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Commercial Commitments

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Letters of credit

 

$

0.8

 

 

 —

 

 

 —