KLX Energy Services Holdings, Inc. 10-K

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (In millions of U.S. dollars and shares) 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.” The following discussion and analysis addresses the results of our operations for the year ended January 31, 2021, as compared to our results of operations for the year ended January 31, 2020. In addition, the discussion and analysis addresses our liquidity, financial condition and other matters for these periods. The previously announced merger of Krypton Merger Sub, Inc., an indirect wholly owned subsidiary of KLXE ("Merger Sub"), with and into Quintana Energy Services Inc. (“QES”), with QES surviving the merger as a subsidiary of KLXE (the "Merger") closed on July 28, 2020. Unless otherwise noted or the context requires otherwise, references herein to KLX Energy Services with respect to time periods prior to July 28, 2020 include KLX Energy Services and its consolidated subsidiaries and do not include QES and its consolidated subsidiaries, while references herein to KLX Energy Services with respect to time periods from and after July 28, 2020 include QES and its consolidated subsidiaries. Company History KLX Energy Services was initially formed from the combination of seven private oilfield service companies acquired during 2013 and 2014. 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. 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 completions 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. In March 2019, the Company acquired Red Bone Services LLC (“Red Bone”), a premier provider of oilfield services primarily in the Mid-Continent, providing fishing, non-hydraulic fracturing high pressure pumping, thru-tubing and certain other services. We successfully completed the integration of the Tecton and Red Bone businesses during Fiscal 2019. We acquired QES during the second quarter of 2020 and, by doing so, helped establish KLXE as an industry leading provider of asset-light oilfield solutions across the full well lifecycle to the major onshore oil and gas producing regions of the United States. On July 26, 2020, the Company’s Board approved a 1-for-5 reverse stock split to stockholders that became effective at 12:01 a.m. on July 28, 2020 (the “Reverse Stock Split”). On July 28, 2020, we successfully completed the all-stock Merger with QES. At the time of the closing, the holders of QES common stock received 0.0969 shares of KLXE common stock in exchange for each share of QES common stock held. KLXE and QES stockholders owned approximately 59% and 41%, respectively, of the equity of the combined company on a fully-diluted basis. As a result of the Merger, our Board is now comprised of nine directors, consisting of five directors designated by KLXE and four directors designated by QES. Additionally, Christopher J. Baker, the former President and Chief Executive Officer of QES, now serves as our President and Chief Executive Officer, and Keefer M. Lehner, the former Executive Vice President and Chief Financial Officer of QES, now serves as our Executive Vice President and Chief Financial Officer. The Merger of KLXE and QES provides increased scale to serve a blue-chip customer base across the onshore oil and gas basins in the United States. The Merger combines two strong company cultures 49 Table of Contents comprised of highly talented teams with shared commitments to safety, performance, customer service and profitability. The combination leverages two of the largest fleets of coiled tubing and wireline assets, with KLXE becoming a leading provider of large diameter coiled tubing and wireline services and one of the largest independent providers of directional drilling to the U.S. market. After closing the Merger, the Company has been focused on integrating personnel, facilities, processes and systems across all functional areas of the organization. As of January 31, 2021, the Company implemented approximately $46.0 of annualized cost savings. We are diligently focused on generating additional cost savings from the Merger and to date have realized such savings through eliminating KLXE's legacy corporate headquarters in Wellington, Florida, rationalizing associated corporate functions to Houston, and capturing operational synergies in the areas of personnel, facilities and rolling stock. Additional synergies may be realized as management continues to rationalize operational facilities and align common roles, processes and systems throughout each function and region. The Merger also enhances the Company’s ability to effect further industry consolidation. Looking ahead, the Company expects to pursue strategic, accretive consolidation opportunities that further strengthen the Company’s competitive positioning and capital structure and drive efficiencies, accelerate growth and create long‑term stockholder value. Company Overview We serve many of the leading companies engaged in the exploration and development of onshore conventional and unconventional oil and natural gas reserves in the United States. Our customers are primarily large independent and major oil and gas companies. We currently support these customer operations from over 50 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, Eagle Ford Shale and the Gulf Coast as well as in industrial and petrochemical facilities), 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 Shale as well as the Mid-Continent STACK and SCOOP and Haynesville Shale) . Our revenues, operating earnings and identifiable assets are primarily attributable to these three reportable geographic segments. While we manage our business based upon these geographic groupings, our assets and our technical personnel are deployed on a dynamic basis across all of our service facilities to optimize utilization and profitability. These expansive operating areas provide us with access to a number of nearby unconventional crude oil and natural gas basins, both with existing customers expanding their production footprint and third parties acquiring new acreage. Our proximity to existing and prospective customer activities allows us to anticipate or respond quickly to such customers’ needs and efficiently deploy our assets. We believe that our strategic geographic positioning will benefit us as activity increases in our core operating areas. Our broad geographic footprint provides us with exposure to the ongoing recovery in drilling, completion, production and intervention related service activity and will allow us to opportunistically pursue new business in basins with the most active drilling environments. We work with our customers to provide engineered solutions across the 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, including their most technically complex extended reach horizontal wells. 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 proprietary equipment. Our innovative and adaptive approach to proprietary tool design has been employed by our in-house R&D organization and, in selected instances, by our technology partners to develop tools covered by 25 patents and 14 pending patent applications, which we believe differentiates us from our regional competitors and also allows us to deliver more focused service and better outcomes in our specialized 50 Table of Contents services than larger national competitors that do not discretely dedicate their resources to the services we provide. 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. This approach leverages our technical strengths, as well as those of our technology partners. These services and related products 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 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 both newer and older legacy wells. 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. We endeavor 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. Segment Reporting The Company changed its presentation of reportable segments related to the allocation of corporate overhead costs to reflect the presentation used by the Company's chief operational decision-making group ("CODM") to make decisions about resources to be allocated to the Company’s reportable segments and to assess segment performance. Historically, and through July 31, 2020, the Company’s total corporate overhead costs were allocated and reported within each reportable segment. During the third quarter of 2020, the Company changed the corporate overhead allocation methodology to only include corporate costs incurred on behalf of its operating segments, which includes accounts payable, accounts receivable, insurance, audit, supply chain, health, safety and environmental and others. The remaining unallocated corporate costs are reported as a reconciling item in the Company’s segment reporting disclosures. The change is reflected retroactively in the accompanying financial statements, which resulted in a decrease to the total corporate overhead costs allocated to our three reportable segments for the year ended January 31, 2021, and 2020 of $62.0 and $54.7, respectively. In conjunction with the change in presentation of reportable segments, the Company also changed its presentation of segment assets. Historically, and through July 31, 2020, the Company’s corporate assets were allocated and reported within each reportable segment. During the third quarter of 2020, the Company changed the presentation of total assets to present corporate assets separately as a reconciling item in its segment reporting disclosures. As a result of the change in presentation, the total corporate assets allocated to the Company’s three reportable segments decreased by $51.9 and $139.1 as of January 31, 2021 and 2020, respectively. 51 Table of Contents The Company also changed its presentation of service offering revenues. Historically, and through July 31, 2020, the Company’s service offering revenues included revenues from the completion, production and intervention market types within segment reporting. During the third quarter of 2020, the Company changed the presentation of its service offering revenues by separately reporting a drilling market type revenue, which includes directional drilling, drilling accommodation units and related drilling support services. The reclassifications are retroactively reported in the Company’s segment reporting disclosures to reflect the drilling revenue change and use of the information by the Company’s CODM. For the year ended January 31, 2021 and 2020, the total drilling revenues reported within segment reporting was $46.7 and $44.4, respectively. These current period changes in the Company’s corporate allocation method and service offering revenue disclosures have no net impact to the consolidated financial statements. The change better reflects the CODM’s philosophy on assessing performance and allocating resources as well as improves the Company’s comparability to its peer group. See Note 15. “Segment Reporting” to our audited consolidated financial statements included elsewhere in this Form 10-K. Recent Trends and Outlook Demand for services in the oil and natural gas industry is cyclical and subject to sudden and significant volatility. Market demand for our services during 2020 was challenged due to the COVID-19 pandemic and macro supply and demand concerns. The oilfield service industry experienced an abrupt deterioration in demand during the second half of 2019, which continued into 2020. During the first quarter of 2020, the emergence of COVID-19, and the global pandemic caused thereby, placed significant downward pressure on the global economy and oil demand and prices, leading North American operators to announce significant cuts to planned 2020 capital expenditures and causing the continued acceleration of upstream oil and gas bankruptcies. In the midst of the ongoing COVID-19 pandemic, OPEC+ were unable to reach an agreement on production levels for crude oil, at which point Saudi Arabia and Russia initiated efforts to aggressively increase production. The convergence of the COVID-19 pandemic and the crude oil production increases caused the unprecedented dual impact of global oil demand decline and the risk of a substantial increase in supply. While OPEC+ agreed in April 2020 to cut production, downward pressure on commodity prices remained through much of Fiscal 2020. WTI's average daily price per barrel decreased by approximately $18.91, or 32.9%, to $38.59 per barrel (“Bbl”) during Fiscal 2020, compared to Fiscal 2019's average daily price per barrel of $57.50. In response to the COVID-19 pandemic and the concurrent Saudi-Russia market share dispute, activity levels in the US plunged to record lows. US operators responded by shutting-in production and drastically reducing drilling and completions activity and associated spending. For example, US operators laid down nearly 70% of active rigs between the first and third quarters of 2020 and a majority of US operators reduced 2020 capital spending by 50% when compared to 2019 and renewed their focus on living within free cash flow. Ultimately OPEC plus curtailed production and stabilized crude prices in mid-2020. This resulted in a material increase in commodity prices over the course of the second half of 2020. US operators remain focused on executing on free cash flow centric strategies but have increased drilling and completion activity meaningfully since the market bottomed in mid-2020. Despite these market headwinds experienced in 2020, the Company remained focused on building a leaner and more profitable set of service offerings, which allowed us to make meaningful positive impacts to our revenue, operating margins, cash flows and Adjusted EBITDA. 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. Our completions services have been the first to reflect an improvement in market activity, as operators have focused on completing their backlog of drilled uncompleted wells from earlier in the year. We began to see an uptick in activity at the end of the second quarter. An increase in completions activity during the fourth quarter 52 Table of Contents of 2020 has driven the activity rebound, while drilling activity has been slower to rebound with rig count bottoming in August 2020 and rebounding 136 rigs, or 59.6%, to 364 rigs as of January 31, 2021. We believe our diverse product and service offerings uniquely positions KLXE to respond to a rapidly evolving marketplace where we can provide a comprehensive suite of engineered solutions for our customers with one call and one master services agreement. The extent and duration of the continued global impact of the COVID-19 pandemic is unknown. While economic activity has increased from the April 2020 lows, and signs of a potential global economic recovery have emerged, driven by the rollout of COVID-19 vaccines, fiscal and monetary stimulus policies, and pent-up demand for goods and services, concerns about a COVID-19 resurgence have hindered the pace of a full return of social and commercial activity. In February of 2021, we experienced a material slow down due to the unprecedented North American Winter Storm Uri, the costliest winter storm in U.S. history. As a result of the storm conditions, our customers shut in wells and delayed work causing us at least seven days of lost revenue, primarily in the Permian and the Mid-continent regions. Looking ahead to Fiscal 2021, provided that the impact of the COVID-19 pandemic lessens, economic activity continues to increase, and commodity prices remain strong, we believe that our customers will sustain activity in order to hold their production flat to 2020 exit levels, with completions spend expected to outpace drilling. So far in Fiscal 2021, WTI prices have increased an incremental 12.8% from February 1 to April 1. In response, US have continued to increase drilling and completion activity levels relative to where the market exited 2020. As of April 1, 2021, US rig count was up to 430, an increase of 12.0% since January 31, 2021. Additionally, we have continued to see US shale operators consolidate within certain basins, particularly the Permian and many operators have announced that they are targeting oil and gas production at the end of 2021 to be consistent with production levels at year end 2020. How We Generate Revenue and the Costs of Conducting Our Business Our business strategy seeks to generate attractive returns on capital by providing differentiated services and prudently applying 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 equipment that is less expensive to maintain and is operated by a smaller staff than many other oilfield service providers. As part of our returns-focused approach to capital spending, we are focused on efficiently utilizing capital to develop 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. Demand for services in the oil and natural gas industry is cyclical and subject to sudden and significant volatility. 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 our operating cost structure is now materially lower than during historical financial reporting periods and the realization of the $46.0 of expected cost synergies associated with the Merger will only further reduce our cost structure and afford us greater flexibility to respond to changing industry conditions. The implementation of integrated, company-wide management information systems and processes provides 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. As of January 31, 2021, the QES integration and the implementation of all synergies was complete. The potential for further cost savings remains as we continue to refine and optimize the business. 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. 53 Table of Contents 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. Historically, we believed our services generated margins superior to our competitors based upon the differential quality of our performance, and that these margins would contribute to future cash flow generation. The required investment in our business includes both working capital (principally for accounts receivable, inventory and accounts payable growth tied to increasing activity and revenues) and capital expenditures for both maintenance of existing assets and ultimately growth when returns justify the spending. Our required maintenance capital expenditures tend to be lower than other oilfield service providers due to the generally asset-light 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. How We Evaluate Our Operations 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 measures we believe most effective to achieve the above stated goals include: • Revenue • Adjusted Earnings before interest, taxes, depreciation and amortization ("EBITDA") : Adjusted EBITDA is a supplemental non-Generally Accepted Accounting Principles ("GAAP") financial measure that is used by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies. Adjusted EBITDA is not a measure of net earnings or cash flows as determined by GAAP. We define Adjusted EBITDA as net earnings (loss) before interest, taxes, depreciation and amortization, further adjusted for (i) goodwill and/or long-lived asset impairment charges, (ii) stock-based compensation expense, (iii) restructuring charges, (iv) transaction and integration costs related to acquisitions and (v) other expenses or charges to exclude certain items that we believe are not reflective of ongoing performance of our business. • Adjusted EBITDA Margin: Adjusted EBITDA Margin is defined as Adjusted EBITDA, as defined above, as a percentage of revenue. We believe Adjusted EBITDA is useful because it allows us to supplement the GAAP measures in order to evaluate our operating performance and compare the results of our operations from period to period without regard to our financing methods or capital structure. We exclude the items listed above in arriving at Adjusted EBITDA (Loss) because these amounts can vary substantially from company to company within our industry depending upon accounting methods, book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDA should not be considered as an alternative to, or more meaningful than, net (loss) earnings as determined in accordance with GAAP, or as an indicator of our operating performance or liquidity. Certain items excluded from Adjusted EBITDA are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of Adjusted EBITDA. Our computations of Adjusted EBITDA may not be comparable to other similarly titled measures of other companies. 54 Table of Contents Results of Operations Year Ended January 31, 2021 Compared to Year Ended January 31, 2020 Revenue . The following table provides revenues by segment for the periods indicated: Year Ended January 31, 2021 January 31, 2020 % Change Revenue: Southwest $ 83.6 $ 177.9 (53.0) % Rocky Mountains 99.3 216.4 (54.1) % Northeast/Mid-Con 93.9 149.7 (37.3) % Total revenue $ 276.8 $ 544.0 (49.1) % For the year ended January 31, 2021, revenues of $276.8 decreased by $267.2, or 49.1%, as compared with the prior year period. Southwest segment revenue declined by $94.3, or 53.0%, Rocky Mountains segment revenue declined by $117.1, or 54.1%, and Northeast/Mid-Con segment revenue declined by $55.8, or 37.3%. On a product line basis, drilling, completion, production and intervention services contributed approximately 16.9%, 52.0%, 16.4% and 14.7%, respectively, to fiscal 2020 revenues. On a product line basis completion, production and intervention services revenues decreased by approximately $150.1, $67.6 and $51.8, respectively, as compared to the same period in the prior year. The overall decrease in revenues reflects the lingering impacts of the unforeseen global oil market share dispute and the prolonged demand destruction caused by the COVID-19 pandemic, resulting in a depression in oil prices, a historically low rig count and, ultimately, decreased demand for services such as those provided by the Company. Drilling revenues increased $2.3, driven primarily by addition of QES's Directional Drilling business as part of the Merger and increased market activities experienced during the fourth quarter of 2020. Cost of sales . For the year ended January 31, 2021, cost of sales was $314.8, or 113.7% of sales, as compared to the prior year period of $470.0, or 86.4% of sales. Cost of sales as a percentage of revenues increased primarily due to negative operating leverage related to the 49.1% year-over-year decline in revenues as the significant decline in revenues outpaced the reduction in fixed costs. Cost of sales included $57.7 and $60.2 of depreciation expense for the year ended January 31, 2021 and 2020, respectively. Selling, general and administrative expenses ("SG&A") . SG&A expenses during the year ended January 31, 2021, were $88.8, or 32.1% of revenues, as compared with $100.0, or 18.4% of revenues, in the prior year period. SG&A decreased primarily due to reductions in payroll and related expenses and bad debt expense of $7.5 and $10.8, respectively, offset by increases in professional fees of $9.6. R&D costs during the year ended January 31, 2021 were $0.7, as compared to the prior year period of $2.7, reflecting our continued focus on maintaining an in-house R&D function while scaling costs to adjust to current levels of customer demand. Fiscal 2020 SG&A expenses include six months of incremental activity related to the Merger, that wasn't included in prior year results. Operating (loss) earnings . The following is a summary of operating (loss) earnings by segment: Year Ended January 31, 2021 January 31, 2020 % Change Operating (loss) earnings: Southwest $ (120.0) $ (37.4) (220.9) % Rocky Mountains (43.4) 32.7 (232.7) % Northeast/Mid-Con (116.0) (16.3) NMF Corporate and other (62.0) (54.7) (13.3) % Bargain purchase gain 40.3 — NMF Total operating (loss) earnings $ (301.1) $ (75.7) (297.8) % 55 Table of Contents For the year ended January 31, 2021, operating loss was $301.1, as compared to operating loss of $75.7 in the prior year period, largely driven by a reduction in revenues due to reduced activity and pricing pressure caused by the COVID-19 pandemic and international pricing and production disputes, as well as non-recurring items related to the Merger and increased impairment and other charges . For the years ended January 31, 2021 and 2020, there were $180.4 and $0.0 impairments of long lived assets. For the years ended January 31, 2021 and 2020, the Company determined goodwill was impaired and recorded goodwill impairment charges of $28.3 and $47.0, respectively. For the year ended January 31, 2021, Rocky Mountains segment operating loss was $43.4, Northeast/Mid-Con segment operating loss was $116.0 and Southwest segment operating loss was $120.0, in each case primarily driven by lower revenues as a result of decreased demand for the Company's products and services. Income tax expense (benefit) . Income tax expense was $0.4 for the year ended January 31, 2021, as compared to income tax benefit of $8.5 in the prior year period, and was comprised primarily of state and local taxes. The Company did not recognize a tax benefit on its year-to-date losses because it has a valuation allowance against its deferred tax balances. Net loss . Net loss for the year ended January 31, 2021 was $332.2, as compared to $96.4 in the prior year period, primarily due to decreased demand, increased impairment and other charges, non-recurring items related to the Merger and integration totaling $39.7, offset by the bargain purchase gain on the Merger of $40.3 as described above. Liquidity and Capital Resources We require capital to fund ongoing operations, including maintenance expenditures on our existing fleet and equipment, organic growth initiatives, investments and acquisitions. Our primary sources of liquidity to date have been capital contributions from our equity and note holders and borrowings under the Company’s ABL Facility and cash flows from operations. At January 31, 2021, we had $47.1 of cash and cash equivalents and $34.9 available on the ABL Facility, net of $10 FCCR holdback, which resulted in a total liquidity position of $82.0. Volatile WTI prices, challenges created by the global COVID-19 pandemic and the current oil supply demand imbalance have further decreased demand for our services. Our cash flows used in operations for the year ended January 31, 2021 were approximately $64.9. In response to declining customer activity and commodity price instability, in the third quarter of 2020 we fully implemented actions to achieve previously announced annualized run-rate cost synergies. However, there is no certainty that cash flow will improve or that we will have positive operating cash flow for a sustained period of time. Our operating cash flow is sensitive to many variables, the most significant of which are utilization and profitability, the timing of billing and customer collections, payments to our vendors, repair and maintenance costs and personnel, any of which may affect our available cash. The COVID-19 pandemic and the related significant decrease in the price of oil resulted in a decrease in demand for our services in the last part of the first quarter through the third quarter. Additionally, should our customers experience financial distress due to the current market conditions, they could default on their payments owed to us, which would affect our cash flows and liquidity. Our primary use of capital resources has been for funding working capital and investing in property and equipment used to provide our services. We actively manage our capital spending and are focused on required maintenance spending. In addition, we regularly monitor potential sources of capital, including equity and debt financings, in an effort to meet our planned capital expenditure and liquidity requirements. The COVID-19 pandemic, coupled with the global crude oil supply and demand imbalance and resulting decline in crude oil prices, has significantly affected the value of our common stock, which may reduce our ability to access capital in the bank and capital markets, including through equity or debt offerings without a viable recovery and uptick in the demand for our services. 56 Table of Contents At January 31, 2021, we had $47.1 of cash and cash equivalents. Cash on hand at January 31, 2021 decreased by $76.4, as compared with $123.5 cash on hand at January 31, 2020 as a result of $64.9 of cash flows used by operating activities primarily related to $29.4 of interest, and $9.7 to pay down QES's five year asset-based revolving credit agreement; and $11.9 of cash flows used in investing activities. Our liquidity requirements consist of working capital needs, debt service obligations and ongoing capital expenditure requirements. Our primary requirements for working capital are directly related to the activity level of our operations. Net working capital as of January 31, 2021 was $35.0, a decrease of $12.4 as compared with net working capital of $47.4 at January 31, 2020. Net working capital is calculated as current assets, excluding cash, less current liabilities, excluding accrued interest and capital lease obligations. As of January 31, 2021, total current assets excluding cash decreased by $1.4 and total current liabilities increased by $11.0. The increase in current assets was primarily related to an accounts receivable-trade, net decrease of $12.2, offset by a $8.8 increase in inventory, net and a $2.0 increase in other current assets. The increase in total current liabilities was due to a $8.0 and $3.0 increase in accounts payable and accrued liabilities, respectively. The following table sets forth our cash flows for the periods presented below: Year Ended January 31, 2021 January 31, 2020 Net cash (used in) provided by operating activities $ (64.9) $ 58.1 Net cash used in investing activities (11.9) (97.7) Net cash provided by (used in) financing activities 0.4 (0.7) Net change in cash (76.4) (40.3) Cash balance end of period $ 47.1 $ 123.5 Net cash (used in) provided by operating activities Net cash used in operating activities was $64.9 for the year ended January 31, 2021, as compared to net cash provided by operating activities of $58.1 for the year ended January 31, 2020. The decrease in operating cash flows was primarily attributable to the decrease in revenues across all operating segments and most service and related product lines driven by the current slowdown and market headwinds. In addition, the overall cash collected from the reduction in working capital could not offset the decline in operating leverage, and thus, the Company incurred an operating loss for the year ended January 31, 2021. Net cash used in investing activities Net cash used in investing activities was $11.9 for the year ended January 31, 2021, as compared to net cash used in investing activities of $97.7 for the year ended January 31, 2020. The cash flow used in investing activities for the year ended January 31, 2021 was primarily driven by critical maintenance capital spending tied to the operation of our existing asset base. These investments were offset by the sale of trucks and other idle assets resulting from the cost reduction initiatives. Net cash provided by (used in) financing activities Net cash provided by financing activities was $0.4 for the year ended January 31, 2021 due to a change in financed payables, compared to net cash used in financing activities of $0.7 for the year ended January 31, 2020. During the year ended January 31, 2021, $0.4 was paid for treasury shares 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 program. 57 Table of Contents Financing Arrangements We entered into a $100.0 ABL Facility on August 10, 2018. The ABL Facility became effective on September 14, 2018 and is scheduled to mature in September 2023. Borrowings under the ABL Facility bear interest at a rate equal to 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. During the third quarter of 2020, the Company included the acquired QES current asset collateral into the borrowing base formula used to calculate the KLXE 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. No amounts were outstanding under the ABL Facility as of January 31, 2021. The effective interest rate under the ABL Facility would have been approximately 2.75% on January 31, 2021. The ABL Facility includes a financial covenant which requires the Company’s consolidated FCCR to be at least 1.0 to 1.0 if availability falls below the greater of $10.0 or 15% of the borrowing base. At all times during the year ended January 31, 2021, availability exceeded this threshold, and the Company was not subject to this financial covenant. As of January 31, 2021, the FCCR was below 1.0 to 1.0. The Company was in full compliance with its credit facility as of January 31, 2021. In conjunction with the acquisition of Motley in 2018, we issued $250.0 principal amount of 11.5% senior secured notes due 2025 (the "Notes") offered pursuant to Rule 144A under the Securities Act of 1933 (as amended, 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 issuance costs for the Notes, total debt as of January 31, 2021 was $243.9. The Notes bear interest at an annual rate of 11.5%, payable semi-annually in arrears on May 1 and November 1. Accrued interest as of January 31, 2021 was $7.2. We believe our cash on hand, along with $34.9 of availability under our $100.0 undrawn ABL Facility, net of $10 FCCR holdback, provides 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. Capital Requirements and Sources of Liquidity Our capital expenditures were $12.2 during the year ended January 31, 2021, compared to $70.8 in the year ended January 31, 2020. We expect to incur between $15.0 and $20.0 in capital expenditures for the year ending January 31, 2022, 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 $100.0 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), none of which was drawn at January 31, 2021. Our ability to satisfy our liquidity requirements depends on our future operating performance, which is affected by prevailing economic and political conditions, the level of drilling, completion, production and intervention services activity for North American onshore oil and natural gas resources, the continuation of the COVID-19 pandemic, and financial and business and other factors, many of which are beyond our control. We believe based on our current forecasts, our cash on hand, the ABL Facility availability, together with our cash flows, 58 Table of Contents will provide us with the ability to fund our operations and make planned capital expenditures for at least the next 12 months. The Company also continues to assess various sources and options including public and private financings to bolster its liquidity and believes that, given current market conditions, it has opportunities to do so. Contractual Obligations As a smaller reporting company, we are not required to provide the disclosure required by Item 303(a)(5)(i) of Regulation S-K. Off-Balance Sheet Arrangements Indemnities, Commitments and Guarantees In the normal course of our business, we make certain indemnities, commitments and guarantees under which we may be required to make payments in relation to certain transactions. These indemnities include indemnities to various lessors in connection with facility leases for certain claims arising from such facility or lease and indemnities to other parties to certain acquisition agreements. The duration of these indemnities, commitments and guarantees varies and, in certain cases, is indefinite. Many of these indemnities, commitments and guarantees provide for limitations on the maximum potential future payments we could be obligated to make. However, we are unable to estimate the maximum amount of liability related to our indemnities, commitments and guarantees because such liabilities are contingent upon the occurrence of events that are not reasonably determinable. Our management believes that any liability for these indemnities, commitments and guarantees would not be material to our financial statements. Accordingly, no significant amounts have been accrued for indemnities, commitments and guarantees. We have employment agreements with certain key members of management expiring on various dates. Our employment agreements generally provide for certain protections in the event of a change of control. These protections generally include the payment of severance and related benefits under certain circumstances in the event of a change of control. Lease Commitments The Company finances its use of certain facilities and equipment under committed lease arrangements provided by various institutions. Since the terms of these arrangements meet the accounting definition of operating lease arrangements, the aggregate sum of future minimum lease payments is not reflected on the consolidated balance sheets. At January 31, 2021, future minimum lease payments under these arrangements approximated $72.1, of which $21.6 is related to long-term real estate leases. See Note 11. “Commitments, Contingencies and Off-Balance Sheet Arrangements” to our audited consolidated financial statements included elsewhere in this Form 10-K. Critical Accounting Policies and Estimates The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with GAAP. The preparation of our financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and related disclosure of contingent assets and liabilities. Certain accounting policies involve judgments and uncertainties to such an extent that there is a reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. We evaluate our estimates and assumptions on a regular basis. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of 59 Table of Contents assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of our financial statements. Emerging Growth Company Status We are an “emerging growth company” and are entitled to take advantage of certain relaxed disclosure requirements. We intend to operate under certain 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. Our election to use the phase-in periods permitted by this election may make it difficult to compare our consolidated financial statements to those of non-emerging growth companies and other emerging growth companies that have opted out of the longer phase-in periods and who will comply with new or revised financial accounting standards. If we were to subsequently elect instead to comply with these public company effective dates, such election would be irrevocable. Accounts Receivable We perform ongoing credit evaluations of our customers and adjust credit limits based upon payment history and the customer’s current creditworthiness, as determined by our review of their current credit information. We continuously monitor collections and payments from our customers and maintain an allowance for estimated credit losses based upon our historical experience and any specific customer collection issues that we have identified. The allowance for doubtful accounts at January 31, 2021 and 2020 was $6.5 and $12.9, respectively. Business Combinations We completed our acquisition of QES on July 28, 2020. QES's results of operations have been included in our financial results for the period subsequent to the acquisition date. Under the acquisition method of accounting, we allocate the fair value of purchase consideration transferred to the tangible assets and intangible assets acquired, if any, and liabilities assumed based on their estimated fair values on the date of the acquisition. The fair values assigned, defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between willing market participants, are based on estimates and assumptions determined by management. The estimated fair value of the assets acquired, net of liabilities assumed, exceeds the purchase consideration, resulting in a bargain purchase gain. When determining the fair value of assets acquired and liabilities assumed, we make significant estimates and assumptions. Our estimates of fair value are based upon assumptions believed to be reasonable, but which are inherently uncertain and unpredictable and, as a result, actual results may differ from estimates. During the measurement period, not to exceed one year from the date of acquisition, we may record adjustments to the assets acquired and liabilities assumed, with a corresponding offset to bargain purchase gain if new information is obtained related to facts and circumstances that existed as of the acquisition date. After the measurement period, any subsequent adjustments are reflected in the consolidated statements of operations. Acquisition costs, such as legal and consulting fees, are expensed as incurred. Goodwill and Intangible Assets, Net Under Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) Topic 350, Intangibles—Goodwill and Other, goodwill and indefinite-lived intangible assets are reviewed at least annually for impairment. Acquired intangible assets with definite lives are amortized over their individual useful lives. As of January 31, 2021, the Company had three reporting units, which were determined based on the guidelines contained in FASB ASC Topic 350, Subtopic 20, Section 35. Each reporting unit constitutes a business, for which there is discrete financial information available that is regularly reviewed by the CODM. 60 Table of Contents Goodwill is tested at least annually as of December 31, and the Company’s management assesses whether there has been any impairment in the value of goodwill by comparing the fair value of the reporting unit to its net carrying value. If the carrying value exceeds its estimated fair value, an impairment loss is recognized for the difference up to the carrying value of goodwill. In this event, the asset is written down accordingly. The fair value is determined using valuation techniques based on estimates, judgments and assumptions that the Company’s management believes are appropriate in the circumstances. For the years ended January 31, 2021 and 2020, the Company determined goodwill was impaired and recorded goodwill impairment charges of $28.3 and $47.0, respectively. See Note 7 for additional information. Long‑Lived Assets Long-lived assets, such as property and equipment and purchased intangibles subject to amortization, are tested for impairment when there is evidence that events or changes in circumstances indicate that the carrying amount of an asset may not be recovered. An impairment loss is recognized when the undiscounted cash flows expected to be generated by an asset (or group of assets) is less than its carrying amount. Any required impairment loss is measured as the amount by which the asset’s carrying value exceeds its fair value and is recorded as a reduction in the carrying value of the related asset and a charge to operating results. For the years ended January 31, 2021 and 2020, there were $180.4 and $0.0 impairments of long lived assets. See Note 7 for additional information. Revenue Recognition Revenue is recognized upon the customer obtaining control of promised goods or services, in an amount that reflects the consideration which is expected to be received in exchange for those goods or services. To determine revenue recognition for arrangements within the scope of ASC Topic 606, the following five steps are performed: (i) identify the contract(s) with a customer; (ii) identify the performance obligations in the contract; (iii) determine the transaction price; (iv) allocate the transaction price to the performance obligations in the contract; and (v) recognize revenue when (or as) the Company satisfies a performance obligation. Revenue is recognized in the amount of the transaction price that is allocated to the respective performance obligation when (or as) the performance obligation is satisfied. Service revenues are recorded over time throughout and for the duration of the service period pursuant to a master services agreement (“MSA”) combined with a completed field ticket or a work order. Revenues from product sales are recognized when the customer obtains control of the product, which occurs at a point in time, typically upon delivery in accordance with the terms of the field ticket or work order. Recent Accounting Pronouncements See Note 2 “Recent Accounting Pronouncements” to our consolidated financial statements for a discussion of recently issued accounting pronouncements. As an “emerging growth company” under the Jumpstart Our Business Startups Act (the “JOBS Act”), we are offered an opportunity to use an extended transition period for the adoption of new or revised financial accounting standards. We operate under 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. Our election to use the phase-in periods permitted by this election may make it difficult to compare our financial statements to those of non-emerging growth companies and other emerging growth companies that have opted out of the longer phase-in periods under Section 107 of the JOBS Act and who will comply with new or revised financial accounting standards. If we were to subsequently elect instead to comply with these public company effective dates, such election would be irrevocable pursuant to Section 107 of the JOBS Act. ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK As a smaller reporting company, we are not required to provide the information required by Item 305 of Regulation S-K. 61 Table of Contents