Exhibit 99.1

Recent developments

KLX Energy Services third quarter financial guidance

On October 22, 2018, we provided guidance with respect to our three months ending October 31, 2018 financial results of expected revenues of approximately $120.0 million, expected Adjusted EBITDA of approximately $26.5 million and expected Adjusted EBITDA margin of approximately 22.1%.

The financial guidance presented above is preliminary, unaudited estimates of what the Company’s performance is expected to be for a quarterly period which has not yet been completed. Accordingly, the actual financial results for the three months ended October 31, 2018 may differ materially from this guidance, including as a result of the review of actual results for the final two weeks of the quarter, finalization of the financial statements for the quarter, completion of review procedures performed by the Company’s independent registered public accounting firm, and other factors and adjustments related to the Company’s financial reporting process.

The financial guidance presented above is based on internal estimates of the Company and information available as of the date hereof. There can be no assurance that the Company’s actual results for the quarter will not differ from this guidance and that such changes will not be material. Accordingly, this guidance should not be viewed or relied upon as a substitute for financial statements to be prepared in accordance with GAAP. The Company’s independent registered public accounting firm has not audited, reviewed or performed any procedures with respect to this guidance and, accordingly, do not express an opinion or any other form of assurance about them. In connection with our quarterly closing and review process for the fiscal quarter with our independent auditors, we may identify items that would require us to make adjustments to the guidance set forth above.

With respect to the Company’s guidance for the three months ending October 31, 2018, the following table presents a reconciliation of the GAAP financial measure net loss to the

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non-GAAP financial measures Adjusted operating earnings (loss) and Adjusted EBITDA of the Company:

(1)   Includes $10.7 of non-cash compensation expense associated with the acceleration of unvested shares of KLX common stock held by our employees related to the sale of KLX to The Boeing Company (“Boeing”) and $7.2 of costs and expenses allocated by our former parent during the third quarter associated with the Spin-Off.

We use the above described adjusted measures to evaluate and assess the operational strength and performance of our business and of particular units of our business. We believe the financial measures above are relevant and useful for investors because they allow investors to have a better understanding of our actual operating performance unaffected by the impact of the non-recurring costs. These financial measures should not be viewed as a substitute for, or superior to, operating earnings, net earnings or net cash flows provided by operating activities (each as defined under GAAP), the most directly comparable GAAP measures, as a measure of the Company’s operating performance.

Motley third quarter financial guidance

On October 22, 2018, Motley provided guidance with respect to its three months ended September 30, 2018 financial results of expected revenues of approximately $33.0 million to $35.0 million, expected EBITDA of approximately $11.0 million to $12.0 million and expected EBITDA margin of approximately 33% to 34%. Motley’s third quarter EBITDA is presented on the same basis as Motley’s Adjusted EBITDA for prior periods; however, there were no adjustments pursuant to such definition during the third quarter.

Motley’s financial guidance presented above is preliminary, unaudited estimates and has not been audited or reviewed by any independent auditing firm. Actual results for the quarter may differ materially from this guidance as a result of, among other things, finalization of the financial statements for the quarter, completion of review procedures performed by Motley’s independent registered public accounting firm, and other factors and adjustments related to Motley’s financial reporting process.

The guidance presented above is based on Motley’s preliminary estimates and information available as of the date hereof. They are not a comprehensive statement of Motley’s financial and operating results for such period. There can be no

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assurance that Motley’s final results for such period will not differ from this guidance and that such changes will not be material. Accordingly, this guidance should not be viewed or relied upon as a substitute for complete financial statements to be prepared in accordance with GAAP or as a measure of Motley’s actual performance. Motley’s independent registered public accounting firm has not audited, reviewed or performed any procedures with respect to this guidance and, accordingly, does not express an opinion or any other form of assurance about them.

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Summary KLX Energy Services historical and pro forma financial information

The following table presents summary historical and pro forma financial data for the Company for the periods indicated below. We derived the summary historical financial data as of January 31, 2018 and 2017, and for each of the fiscal years in the three-year period ended January 31, 2018, from our audited financial statements. We derived the summary historical financial data as of January 31, 2016 from KLX’s accounting records. We derived the summary historical statements of earnings data for the six months ended July 31, 2018 and 2017 and the balance sheet data as of July 31, 2018 from our unaudited condensed financial statements. We derived the summary historical balance sheet data as of July 31, 2017 from our unaudited condensed balance sheet. In our management’s opinion, the unaudited condensed financial statements have been prepared on the same basis as the audited financial statements and include all adjustments, consisting only of ordinary recurring adjustments, necessary for a fair presentation of the information for the periods presented. The summary historical financial data as of and for the six months ended July 31, 2018 and 2017 are not necessarily indicative of the results that may be obtained for a full year. The unaudited condensed financial data for the twelve months ended July 31, 2018 has been derived by adding the data set forth below for the fiscal year ended January 31, 2018 to the corresponding data for the six months ended July 31, 2018 and then subtracting the data for the six months ended July 31, 2017.

The historical statements of earnings (loss) 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 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. Our financial statements 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.

The summary unaudited pro forma condensed combined financial data are based on and have been derived from our historical annual and interim financial statements, including our unaudited condensed balance sheet as of July 31, 2018, our unaudited condensed statements of earnings (loss) for the six months ended July 31, 2018 and 2017, and our audited statements of earnings (loss) for our fiscal year ended January 31, 2018. The unaudited pro forma condensed combined statements of earnings (loss) for the six months ended July 31, 2018 and 2017, for the fiscal

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year ended January 31, 2018 and for the twelve months ended July 31, 2018 give effect to the Spin-Off, the Acquisition, the debt financing and related transactions as if each had occurred on February 1, 2017. The unaudited pro forma condensed combined balance sheet as of July 31, 2018 gives effect to the Spin-Off, the Acquisition, the debt financing and related transactions as if each had occurred on July 31, 2018. In management’s opinion, the unaudited pro forma condensed combined financial statements reflect adjustments that are both necessary to present fairly the unaudited pro forma condensed combined statements of earnings and the unaudited pro forma financial position of our business as of and for the periods indicated, and the pro forma adjustments are based on currently available information and assumptions we believe are reasonable, factually supportable and directly attributable to the Spin-Off, the Acquisition, the debt financing and related transactions, and for purposes of the pro forma condensed combined statements of earnings (loss), are expected to have a continuing impact on us.

The unaudited pro forma condensed combined financial data are not necessarily indicative of what our results of operations or financial position would have been had the Spin-Off, the Acquisition, the debt financing and related transactions occurred on the dates indicated. The unaudited pro forma condensed combined financial data also should not be considered indicative of our future results of operations or financial position. The pro forma adjustments are based upon currently available information and certain assumptions that we believe are reasonable, but actual results may differ from the pro forma adjustments.

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(1)   During the fiscal year ended January 31, 2016, we recorded a $640.2 million goodwill and long-lived asset impairment charge. The continued 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, represented 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. As a result, we determined that our goodwill was fully impaired and recorded a pre-tax impairment charge of $310.4 million. Further, we utilized a combination of cost and market approaches to determine

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the fair value of our long-lived assets, resulting in an impairment charge of $177.8 million related to identified intangibles and $152.0 million related to property and equipment.

(2)   Working capital is defined as current assets, excluding cash and cash equivalents, less current liabilities.

(3)   The following table presents a reconciliation of the GAAP financial measure net (loss) earnings to the non-GAAP financial measures Adjusted operating (loss) earnings, Adjusted EBITDA and Pro Forma Adjusted EBITDA:

(a)   See footnote (1) above.

(b)   We incurred non-recurring costs for the fiscal year ended January 31, 2018 of $3.6 million, of which $3.3 million and $0.3 million were included in selling, general and administrative expense and cost of sales, respectively, primarily associated with KLX’s strategic alternatives review. Non-recurring costs for the six months ended July 31, 2018 included $5.7 million of selling, general and administrative expense associated with KLX’s strategic alternatives review and the Spin-Off of its Energy Services Group business to its stockholders. Non-recurring costs for the fiscal year ended January 31, 2016 were $38.5 million, of which $15.4 million and $23.1 million were included in selling, general and administrative expense and cost of sales, respectively, primarily associated with business separation and start-up costs such as spin-off related costs, expansion initiatives, branding and IT implementation costs. The non-recurring costs of $3.2 million for the pro forma twelve months ended July 31, 2018 were included in selling, general and administrative expense primarily associated with other one-time expenses.

(c)   We expect recurring annual costs to be approximately $8.0 million higher than the expenses historically allocated to us from KLX, reflecting 100% allocation of dedicated corporate resources and the expected higher revenues.

(4)   Represents pro forma total debt less pro forma cash and cash equivalents.

(5)   Represents pro forma total debt divided by Pro Forma Adjusted EBITDA.

(6)   Represents pro forma net debt divided by Pro Forma Adjusted EBITDA.

(7)   Represents Pro Forma Adjusted EBITDA divided by pro forma interest expense.

We use the above described adjusted measures to evaluate and assess the operational strength and performance of the business and of particular segments of the business. We believe the financial measures above are relevant and useful for investors because they allow investors to have a better understanding of our actual operating performance unaffected by the impact of non-recurring costs. These financial measures should not be viewed as a substitute for, or superior to, operating earnings, net earnings or net cash flows provided by operating activities (each as defined under GAAP), the most directly comparable GAAP measures, as a measure of our operating performance.

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Summary Motley historical consolidated financial information

The following table presents summary financial data for Motley for the periods indicated below. The summary historical financial data as of December 31, 2017 and 2016, and for each of the fiscal years in the two year period ended December 31, 2017, has been derived from Motley’s audited financial statements. The summary historical statements of earnings data for the six months ended June 30, 2018 and 2017 and the balance sheet data as of June 30, 2018 has been derived from Motley’s unaudited financial statements. The summary historical balance sheet data as of June 30, 2017 has been derived from Motley’s unaudited balance sheet. In the opinion of Motley’s management, the unaudited financial statements have been prepared on the same basis as the audited financial statements and include all adjustments, consisting only of ordinary recurring adjustments, necessary for a fair presentation of the information for the periods presented. The summary historical financial data as of and for the six months ended June 30, 2018 and 2017 are not necessarily indicative of the results that may be obtained for a full year. The unaudited condensed financial data for the twelve months ended June 30, 2018 has been derived by adding the data set forth below for the year ended December 31, 2017 to the corresponding data for the six months ended June 30, 2018 and then subtracting the data for the six months ended June 30, 2017.

In presenting the financial data in conformity with GAAP, Motley’s management was required to make estimates and assumptions that affect the amounts reported. See Note 2, “Significant Accounting Policies” to Motley’s audited financial statements for a discussion of the accounting policies that Motley’s management believes require subjective and complex judgments that could potentially affect reported results.

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(1)   Working capital is defined as the difference between current assets, excluding cash and cash equivalents, and current liabilities, excluding factoring note payable, the current portion of long-term debt and the current portion of capital leases.

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The following table presents a reconciliation of the GAAP financial measure net (loss) earnings to the non-GAAP financial measure Adjusted EBITDA:

(a)                                 Other expense is defined as loss on disposal of fixed assets and interest expense.

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The Motley business

Founded in 2010, Motley is a Permian-focused completion services company, primarily providing large-diameter coiled tubing services. Motley also provides wireline services and complementary completion services such as pump-down and thru-tubing services. Motley’s blue-chip customer base includes many of the largest and most active E&P operators in the Permian Basin, including Apache, Concho, Devon, Anadarko, EOG and XTO.

Motley generated revenues, Adjusted EBITDA and net income of $99.0 million, $26.7 million and $18.4 million, respectively, for the twelve months ended June 30, 2018. See “Summary Motley historical consolidated financial information” for a reconciliation of Motley’s Adjusted EBITDA to net (loss) earnings, the most comparable measure under GAAP.

We believe Motley’s operations are complementary to ours and will strengthen our presence in the Permian Basin. Motley owns a modern equipment fleet of seven coiled tubing packages, eight wireline packets, including pressure control equipment, ten pump down units and a fleet of thru-tubing tools to enable its premium service offering. Motley continues to add to its fleet, with three coiled tubing packages and two pump down pumps expected to be delivered in the fourth quarter of 2018.

Motley currently employs approximately 250 people and is headquartered in Odessa, Texas.

Competitive strengths

We believe Motley differentiates itself from its competitors due to the following key factors:

·                  Premier completions equipment.  Motley operates a high specification, standardized coiled tubing fleet with seven units and three additional units expected to be delivered in the fourth quarter of 2018. Its newbuild single piece coiled tubing units require less than two hours to deploy compared to five to eight hours for traditional two piece coiled tubing units. Motley also operates a fleet of eight wireline units with full pressure control equipment with one additional wireline unit on order. Motley’s coiled tubing and wireline units deploy with its owned support equipment (cranes, double fluid pumpers, and specialty pump down pumps) to allow more efficient and consistent wellsite operations. Motley also operates ten pump down units and a fleet of thru-tubing tools with two additional pump down units on order.

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·                  Culture of service quality.  Motley focuses on providing customers a culture of service quality and is regarded as one of the most efficient and reliable service providers in the Permian Basin. As part of the company’s culture, field-level personnel have substantial job ownership but supervisors, all the way up to executive level, closely monitor operational performance.

·                  Deep customer relationships.  Motley’s relationships with blue-chip customers include a variety of large, independent E&P operators that have both a global and North American focus, with significant active assets in the Permian Basin. Motley’s executives have a long tenure working in the Permian Basin and customer relationships have been built over a long period of time.

·                  Strong safety record.  Motley has achieved one of the strongest safety records in the industry with a total recordable incident rate of 0.84 per 200,000 hours worked (compared to an industry median of 1.5 per 200,000 hours worked). Motley’s safety program empowers and holds local management teams accountable. We also believe Motley’s reputation for safety also helps recruit employees to work at the company.

·                  Focus on the Permian Basin.  Motley is centrally located within the Permian Basin with facilities in Odessa, Texas, including a coil shop, a wireline shop and a tool/gun shop. The Permian Basin is expected to remain the most active E&P region in the United States. The Permian Basin continues to attract increasing amounts of capital investment, with active rigs in the region increasing by more than 300 since May 2016, an increase of more than 200%. Further, we expect that the Permian Basin will continue to benefit from trends toward drilling and completing more complex wells to increase productivity, which benefit operators such as Motley which own equipment and operations well suited for the most complex wells.

·                  Knowledgeable management team.  Motley’s management team has extensive wireline and coiled tubing experience in the Permian Basin with substantial relationships in the region built over many years.

Operations

Motley provides large-diameter coiled tubing services, wireline services and complementary completion services such as pump-down and thru-tubing.

Coiled tubing

Coiled tubing is a flexible, long metal pipe spooled onto a large reel used to perform intervention services throughout the well lifecycle, including during drilling, completion, production and abandonment. While coiled tubing is suitable for use in a wide range of well types, the recent trend of longer laterals has increased demand for large-diameter coiled tubing as smaller diameter coiled tubing is generally unable to reach past 6,000 feet in a lateral and does not have the strength, annular velocities and weight on bit to reach extended laterals. Coiled tubing is a unique and effective completion technology that has emerged as a preferred service in the completion of horizontal sections in unconventional wells. Motley’s focus on large-diameter coiled tubing and services related to horizontal completions positions the company well to benefit from these trends.

Motley’s coiled tubing service began spooling up in late 2016. Currently, Motley operates a fleet of high capacity units used in well completions (primarily drill out) and a unit used in well

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workover applications. Motley’s coiled tubing units deploy a package of equipment that includes a crane and a combination of job specific ancillaries (e.g., double fluid pumpers, specialty pump down pumps and/or nitrogen pumps), which helps control work quality and enhance margins.

Wireline services

Motley entered the wireline space as its first service line once its business transitioned from being purely a consultancy. Motley has become a wireline service provider of choice, particularly for plug setting and perforating conveyance, which are generally considered the most technically demanding wireline jobs. Each wireline truck operates with three crews each comprised of three field service personnel and an experienced engineer. Motley maintains a standardized fleet, allowing it to stock fewer spare parts and mitigate maintenance costs.

Pump down operations

In conjunction with its introduction of coiled tubing services, Motley introduced pump down services in early 2017. Motley’s fleet of ten pumping units provide a range of services used in well completions and workovers. Motley’s pump down operations are provided on a standalone basis in conjunction with wireline operations or in conjunction with coiled tubing operations, as necessary. Motley has ordered two additional pump down units expected to be delivered in the fourth quarter of 2018.

Thru-tubing rental tools

Motley began offering thru-tubing rental tools in 2017 with the addition of a key, experienced team. Motley has 17 employees dedicated to thru-tubing tools. Motley’s thru-tubing services are used on coiled tubing and workover rig equipment to perform completion, intervention and plug and abandonment work. Motley supplies tools primarily on a rental basis with Motley’s coiled tubing units to select third parties. Motley’s tools include in-house and third-party designs.

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Management’s discussion and analysis

of financial condition and results of operations
(KLX Energy Services)

You should read the following discussion of our results of operations and financial condition together with our audited and unaudited historical financial statements and accompanying notes. 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 our SEC filings under the heading “Risk Factors.”

Our financial statements, which we discuss below, reflect our historical financial condition, results of operations and cash flows. The financial information discussed below, however, 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 the periods presented and do not reflect the impact that the Transactions will have on our financial condition, results of operations and cash flows, including, without limitation, increased levels of indebtedness and interest expense. In this section, dollar amounts are shown in millions, except for per share amounts or as otherwise specified.

Company overview

We are a leading provider of completion, intervention and production services and products to the major onshore oil and gas producing regions of the United States. We offer a broad 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 include independent and major oil and gas companies and project management firms. We actively support these customer operations from 36 service facilities located in the key major shale basins. We manage our business in these basins on a geographic basis, including the Southwest Region (the Permian Basin and Eagle Ford Shale), the Rocky Mountains Region (the Bakken formation, Williston, DJ, Uinta and Piceance Basins and Niobrara Shale) and the Northeast Region (the Marcellus and Utica Shales 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.

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We work with well operators to provide engineered solutions across the entire lifecycle of the well, by streamlining operations, reducing non-productive time and developing cost effective and often customized solutions and customized tools for our customers’ most challenging service needs, which include technical, complex unconventional wells requiring extended reach horizontal laterals and greater completion intensity per well. We believe our growing reputation for delivering differential service outcomes has resulted in the number of our customer agreements growing by over 140%, from over 400 as of January 31, 2016 to over 1,000 as of January 31, 2018. These agreements enable us to work for many of the major and independent E&P companies in North America.

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 R&D organization and, in selected instances, by our technology partners to develop tools covered by 11 patents and 26 U.S. and foreign pending patent applications as well as 21 additional proprietary tools. Our technology partners include manufacturing and engineering companies that produce tools, which we design and utilize in our service offerings.

We utilize outside, dedicated manufacturers to produce our products, which, in many cases, our engineers have developed from the 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 its 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 for continued growth, as the oil and gas industry continues to drill and complete thousands of increasingly complex wells each year and as thousands of older legacy wells require remediation.

KLX Energy Services was 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. 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.

We invest in innovative technology and equipment designed for modern production techniques that increase efficiencies and production for our customers. North American unconventional

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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 technical, 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 11 U.S. patents, have 26 U.S. and foreign pending patent applications and utilize 21 additional proprietary tools, some of which have been developed in conjunction with our technology partners, 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.

We are focused on generating attractive returns on capital through the superior margins achieved by our differentiated services and the prudent application of our cash flow to targeted growth opportunities, which is intended to deliver high returns and short payback periods. Our services 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 margins our differentiated services generate, we believe the rising level of completion intensity in our core operating areas contributes to improved margins and returns. This provides us significant operational leverage, and we believe positions us well to continue to generate attractive returns on capital as industry activity increases and the market for oilfield services improves. 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.

We operate in three segments determined on a geographic basis: the Southwest Region (the Permian Basin and the Eagle Ford Shale), the Rocky Mountains Region (the Bakken formation, Williston, DJ, Uinta and Piceance Basins and Niobrara Shale) and the Northeast Region (the Marcellus and Utica Shale as well as the Mid-Continent STACK and SCOOP and Haynesville). As noted above, 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.

Demand for services in the oil and natural gas industry is cyclical. For example, the domestic E&P industry in the United States underwent a substantial downturn in 2015 and much of 2016, placing unprecedented pressure on both our customers and competitors. However, we believe our Company is well positioned to operate successfully as a stand-alone 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. 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

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centralizing a number of common functions, as evidenced by our reduced use of cash from operations on lower revenues. 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. Profitability levels are dependent more directly on pricing for our services rather than utilization rates; as such, our ability to differentiate ourselves on the basis of quality contributes to revenue growth and profitability even in a stable or declining market environment through market share gains and growing business with existing customers.

Following the completion of the Acquisition, the debt financing and related transactions, we expect our Company to be capitalized with over $100 of cash and over $70 of availability under our undrawn ABL Facility. We believe we have strong management systems in place, which allow us to manage our operating resources and associated expenses relative to market conditions. We believe our services often generate superior margins to our competitors based upon the differential quality of our performance, and that these margins also support strong free 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 are relatively modest compared to other oilfield service providers due to the asset-lite nature of our services, the average age of our assets of less than three years and our ability to charge back a portion of asset maintenance to customers for a number of our assets. In addition to these internal expenditures, we may also pursue additional selected acquisition opportunities. We believe industry conditions are likely to continue to support existing activity levels of oilfield service providers, but that the pace of industry consolidation will pick up, as weakened private company competitors look to take advantage of the market activity to exit.

The Spin-Off

On September 14, 2018, we completed the Spin-Off and became an independent, publicly-traded company. We are party to a number of agreements with KLX, including the Distribution Agreement, the Employee Matters Agreement, the Transition Services Agreement and the IP Matters Agreement. These agreements govern the relationship between us and KLX and provide for the allocation between us and KLX of various assets, liabilities and obligations (including employee benefits, information technology and insurance). Our undrawn $100 ABL Facility is available for borrowing for working capital and other general corporate purposes. Availability under the ABL Facility is tied to the aggregate amount of our accounts receivable and inventory that satisfy specified criteria and currently exceeds $70. 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 also be used for future acquisitions.

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Factors affecting the comparability of our future results of operations to our historical results of operations

Our future results of operations may not be comparable to our historical results of operations for the periods presented, primarily for the Spin-Off related reasons described below:

·                  Expenses Associated with Former Parent’s Strategic Alternatives Review:  During the first quarter of fiscal 2018, $3.8 million of costs and expenses were allocated to us by our former parent associated with its strategic alternatives review.

·                  Initial Expenses to Become a Stand-Alone Public Company:  During the second and third quarters of fiscal 2018, $8.8 million of costs and expenses were allocated to us by our former parent associated with the Spin-Off. In addition, we expect to incur approximately $3.0 to $5.0 million of costs and expenses within 6 to 12 months of the distribution associated with our transition to being a stand-alone public company. These expenses primarily relate to accounting, tax and professional costs, duplicative costs under the Transition Services Agreement between ourselves and our former parent signage, branding and employee retention expenses, and costs related to information technology and systems.

·                  SG&A Allocation:  Selling, general and administrative (“SG&A”) expense includes allocations of general corporate expenses from KLX. The historical statements of earnings (loss) 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. 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. Please see Note 1 to our audited financial statements for a description of the costs allocated, the methods of allocation, the reasons for the allocations and how future actual costs may differ from the amounts allocated under the ownership of KLX.

·                  KLX Restricted Stock:  We will incur approximately $10.7 of non-cash compensation expense associated with the acceleration of unvested shares of KLX shares held by KLX Energy Services employees related to the sale of KLX to Boeing.

·                  Ongoing Stand-Alone Public Company Expenses:  We expect to incur direct, incremental expenses as a result of being a publicly-traded company, including, but not limited to, costs associated with hiring a dedicated corporate management team, annual and quarterly reports, quarterly tax provision preparation, independent auditor fees, expenses relating to compliance with the rules and regulations of the SEC, investor relations activities, registrar and transfer agent fees, incremental director and officer liability insurance costs and independent director compensation. These direct, incremental expenses are not included in

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our historical results of operations. We expect recurring annual costs to be approximately $8.0 higher than the expenses historically allocated to us from KLX, reflecting 100% allocation of dedicated corporate resources and the expected higher revenues.

·                  Impact of Purchase Accounting:  We will perform a purchase price allocation for the acquisition of Motley, which will result in the recognition of identifiable intangible assets, including customer relationships and non-competition arrangements. The identifiable intangible assets will be amortized over their estimated useful life and will result in incremental amortization as compared to historical periods.

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;

·                  Operating earnings growth rate;

·                  Operating margin;

·                  Return on invested capital;

·                  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 will engage its own compensation consultant to recommend performance metrics and targets for our employees.

Six months ended July 31, 2018 as compared to the six months ended July 31, 2017

The following is a summary of revenues by segment:

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For the six months ended July 31, 2018, revenues of $228.2 increased $91.2, or 66.6%, as compared with the prior year period. Our revenue growth was driven by a 75.2%, or $34.5, increase in Southwest revenues, a 60.6%, or $33.2, increase in Rocky Mountains revenues and a 64.7%, or $23.5, increase in Northeast revenues, reflecting the higher level of activity by our customers throughout the regions we serve. Year-over-year revenue growth by PSLs was approximately 96.2% for completion, 33.3% for intervention and 56.5% for production, for the reasons set forth above.

Cost of sales for the period was $167.7, or 73.5% of sales, as compared to $119.6, or 87.3% of sales, in the prior year. Cost of sales as a percentage of revenues improved by approximately 1,380 basis points, due to substantially improved results at all three segments of our business resulting from improved market conditions, operating leverage and increased profitability from superior service quality and technical expertise resulting in a reduction of customers’ non-productive time.

SG&A expense during the six months ended July 31, 2018 was $39.7, or 17.4% of revenues, as compared with $34.8, or 25.4% of revenues, in the prior year. SG&A, as a percentage of revenues, improved by approximately 800 basis points as compared with the prior year period primarily due to increased operating leverage as the 66.6% increase in revenues significantly outpaced the 14.1% increase in SG&A. Research and development costs for the period were $1.3 as compared to $0.8 in the prior year, reflecting our increased focus on in-house research and development to deploy new specialized and proprietary tools and equipment.

Operating earnings of $19.5 improved by $37.7, reflecting continued strong year-over-year improvement driven by a higher level of activity by our customers throughout our geographic regions. 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 products and services due to successful R&D initiatives, the quality and depth of our personnel and resulting incremental operating leverage.

We incurred income tax expense of $0.1 for the six months ended July 31, 2018 and 2017. The effective income tax rate varies from the federal statutory rate of 21% in 2018 (35% in 2017) primarily due to the fact that the Company has a full valuation allowance against its net deferred tax asset. The 2018 federal statutory rate is lower than the prior year as a result of recently enacted tax legislation.

For the six months ended July 31, 2018, net earnings was $19.4 as compared to a net loss of $(18.3) in the prior year period. Net earnings in the first half of 2018 were favorably impacted by the improvements in pricing and activity driven by the overall improvement in the oil and gas sector.

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Segment results

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

For the six months ended July 31, 2018, Southwest revenues of $80.4 increased by $34.5, or 75.2%, as compared to the same period in the prior year. The increase in revenues in the Southwest region was driven by increases in completion, intervention and production of 79.8%, 63.2% and 81.7%, respectively. Southwest operating earnings of $5.2 improved by $14.4 reflecting the increased demand for our products and services and operating leverage inherent in our cost and operating structure.

For the six months ended July 31, 2018, Rocky Mountains revenues of $88.0 increased by $33.2, or 60.6%, as compared to the same period in the prior year. The increase in revenues in the Rocky Mountains region was driven by increases in completion, intervention and production of 125.9%, 5.8% and 50.0%, respectively. Rocky Mountains operating earnings of $6.5 improved by $8.3 reflecting the increased demand for our products and services and operating leverage inherent in our cost and operating structure.

For the six months ended July 31, 2018, Northeast revenues of $59.8 increased by $23.5, or 64.7%, as compared to the same period in the prior year. The increase in revenues in the Northeast region was driven by increases in completion, intervention and production of 85.6%, 48.6% and 48.0%, respectively. Northeast operating earnings of $7.8 improved by $15.0 reflecting the increased demand for our products and services and operating leverage inherent in our cost and operating structure.

Year ended January 31, 2018, as compared to year ended January 31, 2017

The following is a summary of revenues by segment:

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Fiscal 2017 revenues of $320.5 increased $168.3, or 110.6%, as compared with the prior year due to strong revenue growth in each of our segments. Year-over-year revenue growth by PSLs was approximately 108.9%, 173.1% and 62.7% for completion, intervention and production activities, respectively.

Cost of sales for Fiscal 2017 was $269.1, or 84.0% of sales, as compared to $181.3, or 119.1% of sales, for the year ended January 31, 2017 (“Fiscal 2016”). Cost of sales as a percentage of revenues improved by approximately 3,510 basis points, due to substantially improved results at all three segments of our business due to the improving market conditions, operating leverage of fixed costs, improved pricing and benefits from our investments in people, process and organizational systems.

SG&A expense during Fiscal 2017 was $73.4, or 22.9% of revenues, as compared with $60.1, or 39.5% of revenues, in the prior year period. SG&A, as a percentage of revenues, improved by approximately 1,660 basis points in Fiscal 2017 as compared with the prior year primarily due to increased operating leverage as the 110.6% increase in revenues significantly outpaced the 22.1% increase in SG&A. Research and development costs during Fiscal 2017 were $2.0 as compared with $0.3 in the prior year period, reflecting our increased focus on in-house research and development to deploy new specialized and proprietary tools and equipment.

Operating loss of $24.0 improved by $65.5 reflecting continued strong year-over-year improvement principally due to higher levels of activity by our customers and operating leverage of fixed costs related thereto.

Income tax expense for the twelve months ended January 31, 2018 and 2017 was $0.1, reflecting KLX Energy Services’ state and local tax expenses.

Net loss for the year ended January 31, 2018 was $(24.1) as compared to $(89.6) in Fiscal 2016. Net earnings was favorably impacted in Fiscal 2017 by the improvements in pricing and greater demand for completion, intervention and production services as a result of the overall improvement in the oil and gas sector.

Segment results

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

For the year ended January 31, 2018, Southwest revenues of $109.5 increased by $53.0, or 93.8%, as compared to the same period in the prior year. The increase in revenues in the Southwest region was driven by increases in completion, intervention and production activities of 85.3%, 209.0% and 25.4%, respectively. Southwest operating loss of $12.8 improved by 65.5% principally due to higher levels of activity by our customers and operating leverage of fixed costs related thereto.

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For the year ended January 31, 2018, Rocky Mountains revenues of $127.0 increased by $71.2, or 127.6%, as compared to the same period in the prior year. The increase in revenues in the Rocky Mountains region was driven by increases in completion, intervention and production activities of 162.3%, 174.5% and 59.2%, respectively. Rocky Mountains operating loss of $0.8 improved by 96.7% principally due to higher levels of activity by our customers and operating leverage of fixed costs related thereto.

For the year ended January 31, 2018, Northeast revenues of $84.0 increased by $44.1, or 110.5%, as compared to the same period in the prior year. The increase in revenues in the Northeast region was driven by increases in completion, intervention and production activities of 96.0%, 134.0% and 117.0%, respectively. Northeast operating loss of $10.4 improved by 63.3% principally due to higher levels of activity by our customers and operating leverage of fixed costs related thereto.

Year ended January 31, 2017 compared to the year ended January 31, 2016

Fiscal 2016 revenues of $152.2 decreased $99.0, or 39.4%, as compared with the prior year due to the significant downturn in the oil and gas industry resulting in reductions in spending by all of our customers and reductions in both personnel and operating capacity. Year-over-year revenue decline by PSLs was approximately 44.9%, 23.1% and 39.4% for completion, intervention and production activities, respectively.

Cost of sales for Fiscal 2016 was $181.3, or 119.1% of sales, as compared to $282.8, or 112.6% of sales, for the year ended January 31, 2016 (“Fiscal 2015”). Cost of sales as a percentage of revenues increased by approximately 650 basis points, due to the significant downturn in the oil and gas industry and reduced operating leverage.

SG&A expense during Fiscal 2016 was $60.1, or 39.5% of revenues, as compared with $78.5, or 31.3% of revenues, in the prior year period. SG&A, as a percentage of revenues, increased by approximately 820 basis points in Fiscal 2016 as compared with the prior year primarily due to reduced operating leverage resulting from the downturn in the oil and gas industry as the 39.4% decrease in revenues outpaced the 23.4% decrease in SG&A in Fiscal 2016 as compared to the prior year. Research and development costs were $0.3 during Fiscal 2016 as compared with none in the prior year period.

Operating loss of $89.5 improved by $660.8 due to the goodwill and long-lived asset impairment charge in Fiscal 2015.

Income tax expense for the twelve months ended January 31, 2017 and 2016 was $0.1 reflecting KLX Energy Services’ state and local tax expenses.

Net loss for the year ended January 31, 2017 was $(89.6) as compared to $(750.4) in Fiscal 2015. Net earnings was favorably impacted in Fiscal 2016 by a goodwill and long-lived asset impairment charge in Fiscal 2015 that did not repeat in Fiscal 2016.

Liquidity and capital resources

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 sources of liquidity have historically been from advances from KLX and

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cash flow from operations. KLX has historically used a centralized approach to cash management and financing of its operations. Transactions between KLX Energy Services and KLX historically were considered to be effectively settled for cash at the time the transaction was recorded. At July 31, 2018 and January 31, 2018, we did not have any cash on our balance sheet. Our undrawn $100 ABL Facility is available for borrowing. 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. As a result of the $50 capital contribution made to us by KLX on the distribution date related to the Spin-Off, the cash available for general corporate purposes from our debt financing related to the Acquisition, the trend in improved market conditions and cash from operating activities and our financial plans for 2018, as well as the availability of our $100 undrawn ABL Facility (whose availability depends in part on a borrowing base tied to the aggregate amount of our accounts receivable and inventory satisfying specified criteria), we believe we have a solid balance sheet and ample operating liquidity. Availability under the ABL Facility is tied to the aggregate amount of our accounts receivable and inventory that satisfy specified criteria and currently exceeds $70.

Prior to the Spin-Off, KLX, in the normal course of its operations, would sweep cash from our accounts and directly pay certain of our expenses. Any such cash allocated to us will be reflected in cash on our October 31, 2018 balance sheet. To the extent the cash we generated from May 1, 2018 through the September 14, 2018 distribution date is calculated to be less than the allocated cash, we will repay the excess cash to KLX, which would reduce our cash on hand and amounts due to former parent by the same amount. We do not believe any such repayment will be material to the Company.

Working capital as of July 31, 2018 was $49.9, an increase of $11.8 as compared with working capital at January 31, 2018. As of July 31, 2018, total current assets increased by $13.3 and total current liabilities increased by $1.5. The increase in current assets was primarily related to an increase in accounts receivable of $10.8. The increase in total current liabilities was due to an increase in accounts payable of $2.6 offset by a decrease in accrued liabilities of $1.1.

Working capital as of January 31, 2018 was $38.1, an increase of $23.3 as compared with working capital at January 31, 2017. As of January 31, 2018, total current assets increased by $45.7 and total current liabilities increased by $22.4. The increase in current assets was primarily related to an increase in accounts receivable of $43.4. The increase in total current liabilities was primarily due to an increase in accounts payable of $16.4 and accrued liabilities of $6.0.

Working capital as of January 31, 2017 was $14.8, an increase of $5.8 as compared with working capital at January 31, 2016. As of January 31, 2017, total current assets decreased by $9.7 and total current liabilities decreased by $15.5. The decrease in current assets was primarily related to decreases in accounts receivable and inventory of $7.3 and $2.0, respectively. The decrease in total current liabilities was primarily due to decreases in accounts payable and accrued liabilities of $8.3 and $7.2, respectively.

Cash flows

Net cash flows provided by operating activities was $29.7 for the six months ended July 31, 2018 as compared to net cash used in operating activities of $13.8 in the prior year primarily due to a $37.7 improvement in net earnings as compared with the prior year. Cash used in

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investing activities consists of capital expenditures of $35.5 and $21.1 for the six months ended July 31, 2018 and 2017, respectively, and reflects the higher demand levels for our services and equipment. Cash flows from financing activities of $5.8 and $34.9, respectively, for the six months ended July 31, 2018 and 2017 consist of net transfers from KLX.

Net cash flows used in operating activities improved by $28.1 to $9.4 for the year ended January 31, 2018 as compared to $37.5 in the prior year primarily reflecting a significantly improved net loss of $24.1 as compared with $89.6 in the prior year.

Cash used in investing activities consists of capital expenditures of $48.8 and $29.0 for the years ended January 31, 2018 and 2017, respectively.

Cash flows from financing activities of $58.2 and $66.5, respectively, for the years ended January 31, 2018 and 2017 consist of net transfers from KLX.

Net cash flows from operating activities decreased by $47.3 to cash used by operating activities of $37.5 for the year ended January 31, 2017 as compared to cash provided by operating activities of $9.8 in the prior year primarily reflecting a decrease in cash provided by accounts receivable of $50.3, an increase in cash used by accounts payable of $10.0 and an increase in the provision for doubtful accounts resulting in a cash use of $5.4 partially offset by an increase in non-cash compensation of $4.7 and other current and non-current assets of $6.5.

Cash used in investing activities consists of capital expenditures of $29.0 and $98.9 for the years ended January 31, 2017 and 2016, respectively, and an acquisition of $5.3 for the year ended January 31, 2016.

Cash flows from financing activities of $66.5 and $94.4, respectively, for the years ended January 31, 2017 and 2016 consist of transfers from KLX.

Capital spending

Our capital expenditures were $35.5 and $21.1 during the six months ended July 31, 2018 and 2017, respectively. Our capital expenditures were $48.8 and $29.0 during the years ended January 31, 2018 and 2017, respectively. We expect to incur approximately $70.0 in capital expenditures for the year ending January 31, 2019, principally related to our growth and maintenance capital expenditures. 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 (whose availability depends in part on a borrowing base tied to the aggregate amount of our accounts receivable and inventory satisfying specified criteria), which we expect to remain undrawn for at least the next 12 months.

Although we do not budget for acquisitions, pursuing growth through acquisitions is a significant part of our business strategy. Our ability to make significant additional acquisitions for cash will require us to obtain additional equity or debt financing, which we may not be able to obtain on terms acceptable to us or at all. Prior to the Acquisition, all of our previous

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acquisitions over the past five years were financed with funds made available by our former parent company.

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 (whose availability depends in part on a borrowing base tied to the aggregate amount of our accounts receivable and inventory satisfying specified criteria), which we expect to remain undrawn for at least the next 12 months.

Contractual obligations

The following chart reflects our contractual obligations and commercial commitments as of July 31, 2018 giving pro forma effect to the Transactions. 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.

(1)                                 To the extent we incur interest on the ABL Facility, interest payments would fluctuate based on LIBOR or the prime rate pursuant to the terms of the ABL Facility.

Off-balance sheet arrangements

Lease arrangements

We finance our 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 our balance sheets. At January 31, 2018, future minimum lease payments under these arrangements approximated $34.2, of which $23.0 is related to long-term real estate leases. At July 31, 2018, future minimum lease payments under these arrangements approximated $36.4, of which $21.8 is related to long-term real estate leases.

Rent expense for the years ended January 31, 2018, 2017 and 2016 was $19.7, $12.9, and $22.8, respectively.

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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.

We on the one hand, and KLX on the other hand, will indemnify each other against certain liabilities, among others, in connection with our respective businesses and breaches of the Distribution Agreement or the other Spin-Off agreements. The amount of each party’s indemnification obligations for breaches of the Distribution Agreement or the other Spin-Off agreements are limited to $300 in the aggregate.

The indemnification obligations under the Distribution Agreement are subject to certain notice and control of defense provisions, as well as certain limitations and obligations regarding double recovery, payment, mitigation and amount of recovery.

Seasonality

Our operations are subject to seasonal factors and our overall financial results reflect seasonal variations. 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 our Rocky Mountains and Northeast segments, 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 may impose transportation restrictions to prevent damage caused by the spring thaw. Lastly, throughout the year, heavy rains adversely affect activity levels, as well locations and dirt access roads can become impassible in wet conditions. Weather conditions also affect the demand for, and prices of, oil and natural gas and, as a result, demand for our services. Demand for oil and natural gas is typically higher in the fourth and first quarters, resulting in higher prices in these quarters.

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Backlog

We operate under master service agreements (“MSAs”) with our E&P customers, which set forth the terms and conditions for the provision of services and related tools and equipment. Completion services are typically based on a day rate with rates based on the type of equipment and competitive conditions. As a result, we do not record backlog.

Effect of inflation

Inflation has not had and is not expected to have a significant effect on our operations.

Critical accounting policies

The discussion and analysis of our financial condition and results of operations are based upon our 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 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. We provide expanded discussion of our more significant accounting policies, estimates and judgments below. We believe that most of these accounting policies reflect our more significant 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 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 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.

Revenue recognition

Sales of products and services are recorded when the earnings process is complete. Service revenues from oilfield technical services and related tools and equipment are recorded when services are performed and/or equipment is rented pursuant to a completed purchase order or MSA that sets forth firm pricing and payment terms.

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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 July 31, 2018, January 31, 2018 and 2017 was $2.8, $2.3 and $2.7, respectively.

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 six months ended July 31, 2018 and the years ended January 31, 2018 and 2017, there were no impairments of long-lived assets.

Recent accounting pronouncements

See Note 1 “Description of Business and Summary of Significant Accounting Policies—Recent Accounting Pronouncements” to our audited financial statements and Note 2 “Recent Accounting Pronouncements” to our unaudited financial statements for a discussion of recently issued accounting pronouncements. As an “emerging growth company” under 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 intend to 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.

Quantitative and qualitative disclosures about market risk

At July 31, 2018 and January 31, 2018 and 2017, we held no significant derivative instruments that materially increased our exposure to market risks for interest rates, foreign currency rates, commodity prices or other market price risks.

Interest rate risk

Under our ABL Facility, we have interest rate exposure arising from variable interest as any borrowings would be impacted by changes in short-term interest rates.

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Commodity price risk

Fuel purchases expose us to commodity price risk. Our fuel costs consist primarily of diesel fuel used by our various trucks and other motorized equipment. The prices for fuel are volatile and are impacted by changes in supply and demand, as well as market uncertainty and regional shortages. Recently we have been able to pass along price increases to our customers, but we may be unable to do so in the future. We generally do not engage in commodity price hedging activities.

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Management’s discussion and analysis

of financial condition and results of operations (Motley)

You should read the following discussion of Motley’s results of operations and financial condition together with Motley’s audited and unaudited historical financial statements and accompanying notes. 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 and Motley’s current expectations, estimates, assumptions and projections about our industry, business and future financial results. 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 our SEC filings under the heading “Risk Factors.” In this section, other than under the heading “Recent Trends”, dollar amounts are shown in millions, except for per share amounts or as otherwise specified.

Overview

Motley is a Permian-focused completion services company, primarily providing large-diameter coiled tubing services. Motley also provides wireline services and complementary completion services such as pump-down and thru-tubing. Motley’s blue-chip customer base includes many of the largest and most active E&P operators in the Permian, such as Apache, Concho, Devon, Anadarko, EOG and XTO. Motley owns a modern equipment fleet of seven coiled tubing packages, eight wireline packages, including pressure control equipment, ten pump down units and a fleet of thru-tubing tools to enable its premium service offering. Motley continues to add to its fleet, with three coiled tubing packages and two pump down pumps expected to be delivered in the fourth quarter of 2018. Motley generated revenues, Adjusted EBITDA and net income of $99.0, $26.7 and $18.4, respectively, for the twelve months ended June 30, 2018.

Recent trends

Motley’s business is significantly influenced by trends in the markets in which Motley and its customers operate. Recent trends affecting Motley’s operations include the following:

·        Increased crude oil prices.  Crude oil prices have experienced a strong recovery (up 170%) since February 2016, driven by improving demand, a dramatic increase in the U.S. drilling rig count and a mitigation of longer-term supply growth in certain international markets. While prices were somewhat volatile in 2017 amid swelling inventories, supply disruptions, reviving U.S. drilling and completions activity and higher political and economic uncertainty, WTI exceeded $60 per barrel following OPEC’s November 30, 2017 announcement to further extend production cuts through December 2018, and is currently trading at the highest pricing level seen over the past three years based in part on positive inventory data.

·        Highly attractive Permian Basin.  The Permian basin has become the most active oil and gas region in the U.S. due to the low breakeven economics found in the region. Motley’s principal customers, have secured arrangements to transport oil to market, thereby allowing these E&Ps to continue to produce oil at strong margins compared to competitors who do not have such arrangements and eliminating “take-away” issues in the Permian Basin.

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·        Rig count.  Since reaching its lowest levels in May 2016, rig count in the Permian Basin has increased 258% (based on rig count as of October 12, 2018), while the U.S. land rig count ex-Permian Basin increased only 126% over the same period. Currently, over 45% of all U.S. land rigs are located in the Permian Basin. The Permian Basin is expected to remain the most active region in the U.S. with rig count projected to increase 17% from 2017 to 2018.

·        DUC inventory.  The inventory of drilled but uncompleted wells (“DUC”) in crude oil-producing regions of the U.S. has grown significantly since 2014 and represents a considerable upside opportunity for Motley over and above the recovery in drilling activity. The number of DUC wells in crude-oil producing regions of the U.S. has increased 146% since January 2014. The Permian Basin has the largest and fastest growing DUC inventory in the U.S. Recent drilling activity has added to this balance, and Motley is positioned to benefit from the completion of these wells.

·        Well servicing and coiled tubing.  The draw of operators to the Permian Basin with its high liquids content, attractive economics and multiple proven formations have provided for positive developments in both the well servicing and coiled tubing markets, which represents upside for Motley’s completion-oriented services. Particularly, well servicing and coiled tubing presence in the Permian is forecast to more than double from 2016 and capture around 35% of the U.S. market by 2018.

·        Increased use of horizontal wells; increasing complexity of wells.  The preference for utilizing vertical rigs to drill conventional wells shifted in 2009 as operators began to exploit shale plays by leveraging techniques for shale gas production to increasingly drill horizontal wells. We believe 94% of active U.S. land rigs are horizontal. As drilling and fracking techniques have improved, operators have extended lateral lengths of wells and increased the number of frac stages per well in order to enhance production rates. Leading edge lateral lengths have exceeded 10,000 feet in some plays. Frac stages per well are pushing boundaries as operators in certain regions have implemented stimulations using 100 or more frac stages. In addition, increasing intensity and corresponding cost of completions (55%-70% of total well cost, which is increasing) make service quality increasingly important in order to prevent costly downtime. These secular trends are expected to benefit Motley as its large-diameter coiled tubing units and wireline and pump down services are well suited for modern, complex wellbores.

·        Increased demand for large diameter coiled tubing units.  Coiled tubing units with diameters of 23/8” and greater are increasingly being utilized for completions versus smaller diameter (e.g., 2”) units due to increased efficiency of operation (increased weight on bit, annular velocities and strength of tubing), especially in longer laterals. Motley’s focus on large diameter coiled tubing units positions Motley to benefit from this trend.

·        U.S. well servicing recovery.  Supported by a cyclical recovery and compounding secular trends, the well servicing market is expected to grow more than 56% annually from 2016 to 2018. The projected increase in well service rigs utilization presents a significant opportunity to drive enhanced utilization and increased pricing of all of Motley’s service lines.

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Results of operations

Six months ended June 30, 2018 as compared to the six months ended June 30, 2017

The following table summarizes Motley’s results of operations for the six months ended June 30, 2018 and 2017:

Revenues.  For the six months ended June 30, 2018, revenues of $58.6 increased $36.5, or 165.2%, as compared with the prior year period. This increase was primarily due to increased demand for Motley’s products and services driven by the continued recovery in the major oil and gas producing basins of the onshore U.S. market.

Cost of services.  Cost of services for the six months ended June 30, 2018 was $37.4, or 63.8% of sales, as compared to $16.8, or 76.0% of sales, in the prior year. Cost of services as a percentage of revenues improved by 1,220 basis points, due to improved results resulting from improved market conditions and operating leverage.

Selling, general and administrative.  Selling, general and administrative expenses (“SG&A”) during the six months ended June 30, 2018 was $3.2, or 5.5% of revenues, as compared with $1.8, or 8.1% of revenues, in the prior year. SG&A, as a percentage of revenues, improved by approximately 260 basis points as compared with the prior year period primarily due to increased operating leverage as the 165.2% increase in revenues significantly outpaced the 77.8% increase in SG&A.

Operating earnings.  Operating earnings of $14.7 improved by $12.4 reflecting improvements in market conditions and the operating leverage inherent in our business.

Net earnings.  For the six months ended June 30, 2018, net earnings was $13.0 as compared to $1.7 in the prior year period. The changes in net earnings are due to the various factors discussed above.

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Year ended December 31, 2017 compared to the year ended December 31, 2016

The following table summarizes Motley’s results of operations for the years ended December 31, 2017 and 2016:

Revenues.  For the year ended December 31, 2017, revenues of $62.5 increased $48.2, or 337.1%, as compared with the prior year. This increase was primarily driven by a higher level of activity by Motley’s customers.

Cost of services.  Cost of services for the year ended December 31, 2017 was $46.4, or 74.2% of sales, as compared to $13.8, or 96.5% of sales, in the prior year. Cost of services as a percentage of revenues improved by 2,230 basis points, due to the improved market conditions and operating leverage.

Selling, general and administrative.  SG&A during the year ended December 31, 2017 was $3.9, or 6.2% of revenues, as compared with $1.4, or 9.8% of revenues, in the prior year. SG&A, as a percentage of revenues, improved by 360 basis points as compared with the prior year primarily due to increased operating leverage as the 337.1% increase in revenues significantly outpaced the 178.6% increase in SG&A.

Operating earnings (loss).  Operating earnings of $8.9 improved by $10.3 as compared to loss of $(1.4), reflecting continued strong year-over-year improvement in the market demand and operating leverage inherent in our business.

Net earnings (loss).  For the year ended December 31, 2017, net earnings was $7.1 as compared to a net loss of $(1.6) in the prior year period due to the various factors discussed above.

Liquidity and capital resources

Motley’s liquidity has historically been principally used to service Motley’s debt and meet Motley’s working capital requirements and capital expenditure needs. Historically, Motley has met its liquidity and capital needs with loans from its members and related parties, bank financing and the issuance of vehicle and equipment financing notes. As of June 30, 2018, Motley had outstanding long-term debt of $30.8 and cash on-hand of $1.6.

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On March 16, 2018, Motley entered into a revolving credit, term loan, equipment loan and security agreement (the “PNC Agreement”) with PNC Bank National Association (“PNC”) which provides for a revolving credit note with a borrowing limit of $20.0 and a term note in the amount of $8.0. Both the revolving credit note and the term note mature on March 16, 2021. Interest on the revolving credit note is payable monthly at the rate of 1.5% plus PNC’s Base Rate (determined by the lender and not tied to external rates). Interest on the term note is determined at the rate of 2.5% plus PNC’s Base Rate. The term note also requires monthly principal payments of approximately $0.1. The revolving credit note and the term note are subject to various covenants and are guaranteed by Motley’s members who pledged their full membership interest as collateral. As of June 30, 2018, Motley had $8.1 and $7.3 outstanding under the revolving credit note and the term note, respectively. The revolving credit note and the term note are expected to be repaid and the PNC Agreement is expected to be terminated in connection with the consummation of the Acquisition.

On April 1, 2018, Motley entered into a capital lease agreement for eight pump down units and two frac units with Hercules Equipment Management, LLC, owned by District 5 Investment, LP, Motley’s related party. The lease agreement matures on September 30, 2021 and requires monthly payments of approximately $0.3, consisting of principal and interest. The market value of the equipment leased under the lease agreement is $10.9. The lease agreement with Hercules Equipment Management, LLC is expected to be terminated and the assets transferred to Motley in connection with the consummation of the Acquisition.

In October and November 2016, Motley issued notes payable to D-5 Investments, LLC, in the aggregate amount of $5. The notes mature on September 30, 2019 and require (i) from November 1 2016, to June 1, 2017, monthly interest payments at a rate of 12% and (ii) from July 1, 2017 to September 1, 2019, monthly payments of principal of $0.05 plus interest accrued on the outstanding loan balance at a rate of 12%. The notes are secured by all Motley’s assets that are not subject to liens. As of June 30, 2018, Motley had $4.4 outstanding under the notes payable to D-5 Investments, LLC. The notes are expected to be terminated and repaid in connection with the consummation of the Acquisition.

Motley is also a party to a number of vehicle financing notes and equipment financing notes payable to third parties and secured by the respective vehicles and equipment. As of June 30, 2018, the aggregate amount due under the vehicle financing notes and equipment financing notes was $4.7. Motley’s vehicle financing notes and equipment financing notes are expected to be terminated in connection with the consummation of the Acquisition. The purchase price will be adjusted for any notes that are not terminated.

Cash flows

Six months ended June 30, 2018 as compared to the six months ended June 30, 2017

Net cash provided by (used in) operating activities.  Net cash provided by operating activities increased by $9.4 to $7.3 for the six months ended June 30, 2018 as compared to net cash used in operating activities of $(2.1) in the prior period primarily reflecting net earnings of $13.0 as compared with $1.7 in the prior period, and $3.3 in depreciation expense ($1.2 in the prior period) offset by a $8.5 increase in accounts receivable ($7.3 in the prior period).

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Net cash used in investing activities.  Net cash used in investing activities was $(12.9) for the six months ended June 30, 2018 as compared to $(1.5) in the prior period. The $11.5 variance was primarily the result of $13.0 capital expenditures as compared with $1.5 in the prior period.

Net cash provided by financing activities.  Net cash provided by financing activities was $6.2 for the six months ended June 30, 2018 as compared to $3.7 in the prior period. This $2.5 increase was primarily related to $7.6 of borrowings on the line of credit (none in the prior year) offset by $1.5 repayment of long term debt in the current period ($0.4 in the prior period).

Year ended December 31, 2017 compared to the year ended December 31, 2016

Net cash provided by (used in) operating activities.  Net cash provided by operating activities increased by $3.1 to $2.7 for the year ended December 31, 2017 as compared to net cash used in operating activities of $(0.4) in the prior year primarily reflecting net earnings of $7.1 as compared with a net loss of $(1.6) in the prior year, $3.3 in depreciation expense ($0.5 in the prior year) and an increase in accounts payable of $4.4 ($1.2 in the prior year) offset by a $11.9 increase in accounts receivable ($0.6 in the prior year).

Net cash used in investing activities.  Net cash used in investing activities was $(6.7) for the year ended December 31, 2017 as compared to $(13.2) in the prior year. The $6.5 variance was primarily the result of lower capital expenditures in the current year.

Net cash provided by financing activities.  Net cash provided by financing activities was $4.6 for the year ended December 31, 2017 as compared to $13.7 in the prior year. This $9.1 decrease was primarily related to $6.7 of borrowings on long-term debt in the prior year (none in the current year) and $10.1 in contributions received in the prior year (none in the current year) offset by $6.4 of proceeds from factoring receivables in the current year (none in the prior year).

Off-balance sheet arrangements

Motley has not entered into any transactions, agreements or other contractual arrangements that would result in off-balance sheet liabilities.

Critical accounting policies and estimates

See Note 2 to Motley’s audited financial statements for information regarding Motley’s critical accounting policies and estimates.

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