QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For The Quarterly Period Ended October 31, 2021
☐
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
Commission File No. 001-38609
KLX Energy Services Holdings, Inc.
(Exact name of registrant as specified in its charter)
Delaware
36-4904146
(State of Incorporation)
(I.R.S. Employer Identification No.)
3040 Post Oak Boulevard, 15th Floor
Houston, TX77056
(832) 844-1015
(Address, including zip code, and telephone number, including area code, of principal executive offices of registrant)
Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class
Trading Symbol(s)
Name of Each Exchange on Which Registered
Common Stock, $0.01 Par Value
KLXE
The Nasdaq Global Select Market
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes☒ No ☐
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes☒ No ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer
☐
Accelerated filer
☐
Non-accelerated filer
☒
Smaller reporting company
☒
Emerging growth company
☒
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒
The registrant has one class of common stock, $0.01 par value, of which 10,346,840 shares were outstanding as of December 3, 2021.
Notes to Condensed Consolidated Financial Statements
(Unaudited – In millions of U.S. dollars)
NOTE 1 - Description of Business and Basis of Presentation
Description of Business
KLX Energy Services Holdings, Inc. (the “Company”, “KLXE” or “KLX Energy Services”) is a growth-oriented provider of diversified oilfield services to leading onshore oil and natural gas exploration and production (“E&P”) companies operating in both conventional and unconventional plays in all major active basins throughout the United States. The Company delivers mission critical oilfield services focused on drilling, completion, production and intervention activities for the most technically demanding wells from over 50 service and support facilities located throughout the United States.
The Company offers a complementary suite of proprietary products and specialized services that is supported by technically skilled personnel and a broad portfolio of innovative in-house manufacturing, repair and maintenance capabilities. KLXE’s primary services include coiled tubing, directional drilling, thru-tubing, hydraulic fracturing rentals, fishing, pressure control, wireline, rig-assisted snubbing, fluid pumping, flowback, pressure pumping and special situation services. KLXE’s primary rentals include hydraulic fracturing stacks, blow out preventers, tubulars, downhole tools, and accommodation units. KLXE's primary product offering includes a suite of proprietary dissolvable and composite plugs along with liner hangers, stage cementing tools, inflatables, and float/casing equipment.
On July 24, 2020, KLXE stockholders approved an amendment to the amended and restated certificate of incorporation of KLXE (the “Reverse Stock Split Amendment”) to effect a reverse stock split of KLXE common stock at a ratio within a range of 1-for-5 and 1-for-10 (the “Reverse Stock Split”), as determined by KLXE’s Board of Directors (the “Board”). The Board subsequently resolved to implement the Reverse Stock Split at a ratio of 1-for-5.
On July 28, 2020, KLX Energy Services, Krypton Intermediate, LLC, an indirect wholly owned subsidiary of KLXE, Krypton Merger Sub, Inc., an indirect wholly owned subsidiary of KLXE (“Merger Sub”), and Quintana Energy Services Inc. (“QES”) completed the previously announced acquisition of QES, by means of a merger of Merger Sub with and into QES, with QES surviving the merger as a subsidiary of KLXE (the “Merger”).
Basis of Presentation
The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) for interim financial information and pursuant to the rules and regulations of the Securities and Exchange Commission (the “SEC”). Accordingly, they do not include all of the information and footnotes required by GAAP for complete financial statements. All adjustments which, in the opinion of the Company’s management, are considered necessary for a fair presentation of the results of operations for the periods shown are of a normal recurring nature and have been reflected in the condensed consolidated financial statements. The results of operations for the periods presented are not necessarily indicative of the results expected for the full fiscal year 2021 or for any future period. The information included in these condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and accompanying notes included in the Company’s 2020 Annual Report on Form 10-K filed with the SEC on April 28, 2021.
The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts and related disclosures. Actual results could differ from those estimates.
The accompanying unaudited condensed consolidated financial statements present the consolidated KLXE and QES financial position as of October 31, 2021 and January 31, 2021. Combined results for both legacy KLXE and legacy QES are included for the entire period in the condensed consolidated statements of operations and cash flows for the three and nine months ended October 31, 2021. The condensed consolidated statements of operations and cash flows for the three and nine months ended October 31, 2020 includes QES’s results for the final three days of the Company's second fiscal quarter, July 29, 2020 through July 31, 2020.
On September 3, 2021, the Board of the Company adopted the Fourth Amended and Restated Bylaws of the Company, effective as of such date, to change the Company’s fiscal year-end from January 31 to December 31, effective beginning with the year ending December 31, 2021. As a result, the Company’s current fiscal year 2021 will be shortened from 12 months to 11 months and end on December 31, 2021. The Company is undertaking this change in an effort to normalize our fiscal year-end and improve comparability with our peers.
Depreciation and Amortization
The Company changed its presentation of depreciation and amortization expense in the first quarter of 2021. Depreciation and amortization expense is presented separately from cost of sales and selling, general, and administrative expenses. Prior period results have been reclassified to conform with current presentation.
Segment Reporting
During the third quarter of 2020, the Company changed its presentation of reportable segments related to the allocation of corporate overhead costs to reflect the presentation used by the Company's chief operational decision-making group ("CODM") to make decisions about resources to be allocated to the Company’s reportable segments and to assess segment performance. Historically, and through July 31, 2020, the Company’s total corporate overhead costs were allocated and reported within each reportable segment. Starting in the third quarter of 2020, the Company changed the corporate overhead allocation methodology to only include corporate costs incurred on behalf of its operating segments, which includes accounts payable, accounts receivable, insurance, audit, supply chain, health, safety and environmental and others. The remaining unallocated corporate costs are reported as a reconciling item in the Company’s segment reporting disclosures. See Note 14 for additional information. As a result of the change in presentation, the total corporate overhead costs allocated for the three and nine months ended October 31, 2020 to the Company’s three reportable segments decreased by $11.4 and $13.7, respectively.
The Company also changed its presentation of service offering revenues. Historically, and through July 31, 2020, the Company’s service offering revenues included revenues from the completion, production and intervention market types within segment reporting. During the third quarter of 2020, the Company changed the presentation of its service offering revenues by separately reporting a drilling market type revenue, which includes directional drilling, drilling accommodation units and related drilling support services. The reclassifications are retroactively reported in the Company’s segment reporting disclosures to reflect the drilling revenue change and use of the information by the Company’s CODM.
These changes in the Company’s corporate allocation method and service offering revenue disclosures have no net impact to the condensed consolidated financial statements. The changes better reflect the CODM’s philosophy on assessing performance and allocating resources as well as improve the Company’s comparability to its peer group.
Property and Equipment, Net
Property and equipment are stated at cost and depreciated generally under the straight-line method over their estimated useful lives of one to forty years (or the lesser of the term of the lease for leasehold improvements, as appropriate). During the quarter, as a result of increased usage from improving drilling activity levels and changes in the manner and conditions in which various types of our small tools are used, we updated the
estimated useful lives of such tools to 1 - 3 years, resulting in approximately $0.2 of incremental monthly depreciation on a prospective basis.
NOTE 2 - Recent Accounting Pronouncements
Accounting Standard Update not yet Adopted
In March 2020, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2020-04, Reference Rate Reform (“Topic 848”): Facilitation of the Effects of Reference Rate Reform on Financial Reporting. This ASU provides optional guidance for a limited period of time to ease the potential burden in accounting for (or recognizing the effects of) reference rate reform on financial reporting and, particularly, the risk of cessation of the London Interbank Offered Rate (“LIBOR”). The amendments in this ASU are elective and apply to all entities, subject to meeting certain criteria, that have contracts, hedging relationships, and transactions that reference LIBOR or another reference rate expected to be discontinued because of reference rate reform. The expedients and exceptions provided by the amendments in this ASU are effective for all entities, if elected, as of March 12, 2020 through December 31, 2022. While the exact impact of this standard is not known, the guidance is not expected to have a material impact on the Company’s condensed consolidated financial statements.
Financial Services industry and market participants continue to work towards transitioning away from interbank offered rates ("IBOR"), including the LIBOR, that are being phased out imminently. This phasing out will have an impact on the ABL Facility (defined below) that utilizes LIBOR as a benchmark. To transition from IBOR Reference Rate, the ABL Facility agreement between the Company and JP Morgan Chase & Co. ("JP Morgan"), which currently has borrowings outstanding of $30.0, will be amended to adopt an alternate rate effective on or before June 30, 2023.Until the ABL Facility agreement is amended to allow for Secured Overnight Financing Rate ("SOFR") as the replacement to LIBOR, the Alternate Base Rate ("ABR"), is the default rate that JP Morgan has agreed to use as the LIBOR replacement.
In December 2019, FASB issued ASU 2019-12, Income Taxes (“Topic 740”): Simplifying the Accounting for Income Taxes. This ASU is intended to simplify aspects of income tax approach for intraperiod tax allocations when there is a loss from continuing operations and income or a gain from other items, and to provide a general methodology for calculating income taxes in an interim period when a year-to-date loss exceeds the anticipated loss for the year. Topic 740 also provides guidance to simplify how an entity recognizes a franchise tax (or similar tax) that is partially based on income as an income-based tax and account for any incremental amount incurred as a non-income-based tax, and evaluations of when step ups in the tax basis of goodwill should be considered part of a business combination. Companies should also reflect the effect of an enacted change in tax laws or rates in the annual effective tax rate computation in the interim period that includes the enactment date. The guidance is effective for the Company for the fiscal year beginning January 1, 2022. While the exact impact of this standard is not known, the guidance is not expected to have a material impact on the Company’s condensed consolidated financial statements.
In June 2016, FASB issued ASU 2016-13, Financial Instruments - Credit Losses (“Topic 326”): Measurement of Credit Losses on Financial Instruments. This ASU is intended to update the measurement of credit losses on financial instruments. This update improves financial reporting by requiring earlier recognition of credit losses on financing receivables and other financial assets in scope by using the Current Expected Credit Losses (“CECL”) model. This guidance is effective for interim and annual periods beginning after December 15, 2022, with early adoption permitted. The new accounting standard introduces the CECL methodology for estimating allowances for credit losses. The Company is an oilfield service company and as of October 31, 2021 had a third-party accounts receivable balance, net of allowance, of $102.9. Topic 326 is not expected to have a material impact on the Company’s condensed consolidated financial statements.
In February 2016, FASB issued ASU 2016-02, Leases (“Topic 842”), which supersedes ASC Topic 840, Leases. Topic 842 requires lessees to recognize a lease liability and a lease asset for all leases, including operating leases, with a term greater than 12 months on its balance sheet. The update also expands the required quantitative and qualitative disclosures surrounding leases. Topic 842 will be applied using a
modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. In November 2019, FASB deferred the effective date for implementation of Topic 842 by one year and, in June 2020, FASB deferred the effective date by an additional year. The guidance under Topic 842 is effective for fiscal years beginning after December 15, 2021 and interim periods within fiscal years beginning after December 15, 2022. Earlier adoption is permitted. To assess the impact of this guidance, the Company has established a cross functional implementation project team and is currently in the process of accumulating and evaluating all the necessary information required to properly account for its lease portfolio under the new standard. The Company is in the process of developing its new accounting policies and determining the potential aggregate impact this guidance is likely to have on its condensed consolidated financial statements as of its adoption date.
NOTE 3 - Business Combinations
QES Merger
On July 28, 2020, the Company completed the Merger with QES, a diversified provider of oilfield services to onshore oil and natural gas E&P companies operating in the United States. The Merger purchase price was approximately $44.4 inclusive of cash paid to settle QES debt, comprised of 3.4 million shares of the Company’s common stock. Based on the Company’s preliminary purchase price allocation, the purchase price was less than the fair value of the identifiable assets acquired, which resulted in a $39.8 bargain purchase gain being recorded in fiscal 2020. In connection with the closing of the Merger, $9.7 in outstanding borrowings and associated fees and expenses of QES's five-year asset-based revolving credit agreement (the “QES ABL Facility”) were paid off. In addition, the Company assumed certain QES compensation agreements, including restricted stock units ("RSU"), with an estimated fair value of $2.0. Based on the service period related to the period prior to the acquisition date, $0.4 was allocated to the purchase price, and $1.6 relating to post-acquisition services will be recorded as operating expenses over the remaining requisite service periods. As of the Merger date, each unvested QES RSU was converted into a KLXE RSU award at a conversion rate of 0.0969 and valued on July 28, 2020.
The Merger was accounted for as a purchase under FASB ASC 805, Business Combinations (“ASC 805”). The results of operations for the acquisition are included in the accompanying condensed consolidated statements of operations from the respective date of acquisition.
The following table summarizes the final fair values of assets acquired and liabilities assumed in the Merger in accordance with ASC 805:
QES
Cash
$
8.7
Accounts receivable-trade
12.2
Inventories
11.8
Other current and non-current assets
7.4
Property and equipment
84.2
Accounts payable
(27.1)
Other current and non-current liabilities
(13.0)
Bargain purchase
(39.8)
Total purchase price (1)
$
44.4
(1) The total consideration of the Merger was approximately $44.4, which was comprised of 3.4 million shares of the Company's common stock and cash paid to settle QES debt.
The Company has substantially integrated portions of the QES business and, as a result, it is not practicable to report stand-alone revenues and operating (loss) earnings of the QES business since the Merger date.
Merger and integration costs were recorded separately from the acquisition of assets and assumptions of liabilities in the Merger. Merger costs consist of legal and professional fees and accelerated stock compensation expense. Integration costs consist of expenses to relocate corporate headquarters, integrate the QES business, reduce headcount, and consolidate service and support facilities. Integration of the QES business is complete and the Company incurred no merger and integration costs for the three months ended October 31, 2021.
The following table presents merger and integration costs that were recorded for the three and nine months ended October 31, 2021 and 2020 in the interim condensed consolidated statements of operations by line item:
Three Months Ended
Nine Months Ended
October 31, 2021
October 31, 2020
October 31, 2021
October 31, 2020
Cost of sales
$
—
$
2.7
$
1.2
$
3.0
Selling, general and administrative
—
2.7
0.5
28.9
Lease termination costs (part of impairment and other charges)
—
4.4
0.6
4.4
Total merger and integration costs
$
—
$
9.8
$
2.3
$
36.3
As of October 31, 2021 and January 31, 2021, accrued lease termination costs were:
Beginning balance as of January 31, 2021
$
3.4
Charged to costs and expenses
0.6
Deductions
(0.9)
Balance as of April 30, 2021
3.1
Deductions
(0.6)
Balance as of July 31, 2021
2.5
Deductions
(0.2)
Ending balance as of October 31, 2021
$
2.3
The following table presents merger and integration costs that were recorded for the three and nine months ended October 31, 2021 and 2020 in the interim condensed consolidated statements of operations by type:
Inventories are primarily made up of composite and dissolvable plugs, spare parts and consumables used to perform services for customers. The Company values inventories at the lower of cost or net realizable value. Inventories are reported net of obsolescence reserves of $2.6 and $2.4 as of October 31, 2021 and January 31, 2021, respectively.
NOTE 6 - Property and Equipment, Net
Property and equipment, net consisted of the following:
Useful Life (Years)
October 31, 2021
January 31, 2021
Land, buildings and leasehold improvements
1
—
40
$
39.5
$
43.7
Machinery
1
—
20
222.2
221.8
Furniture and equipment
1
—
15
183.5
183.2
Property and equipment
445.2
448.7
Less accumulated depreciation
275.5
245.0
Total property and equipment, net
$
169.7
$
203.7
Depreciation expense was 13.6 and $14.7 for the three months ended October 31, 2021 and 2020, respectively, and $43.4 and $40.0 for the nine months ended October 31, 2021 and 2020, respectively.
Depreciation of assets is computed using the straight-line method over the lesser of the estimated useful lives of the respective assets or the lease term, if shorter. During the quarter, as a result of increased usage from improving drilling activity levels and changes in the manner and conditions in which various types of our small tools are used, we updated the estimated useful lives of such tools to 1 - 3 years, resulting in approximately $0.2 of incremental monthly depreciation on a prospective basis.
Assets Held for Sale
As of October 31, 2021, the Company’s condensed consolidated balance sheet included assets classified as held for sale of $2.6. The assets held for sale were reported within other current assets on the condensed consolidated balance sheet and represented the value of three operational facilities and select equipment. In light of the current market environment and as part of the global integration of the QES business, the Company has consolidated operations within certain geographies rendering these locations unnecessary to support the efficient operations of the Company. These assets were being actively marketed for sale as of October 31, 2021 and were recorded at the lower of their carrying value or fair value less costs to sell. During the three months ended October 31, 2021, the Company completed the sale of one aircraft with a carrying value of $0.8 for total sales proceeds of $1.9 and one operational facility with a carrying value of $0.7 for total sales proceeds of $0.7.
NOTE 7 - Goodwill and Intangible Assets, Net
Amortization expense associated with gross intangible assets of $5.7 was $0.1 and nil for the three months ended October 31, 2021 and 2020, respectively, and $0.2 and $3.8 for the nine months ended October 31, 2021 and 2020, respectively. During the three months ended October 31, 2020, accelerated amortization of $2.7 was recognized related to the Company's customer contracts and relationships long-lived intangible. The remaining intangible balance will be amortized straight-line over 7.5 years.
Goodwill and indefinite life intangible assets are tested for impairment annually or on an interim basis if events or circumstances indicate that the fair value of the asset has decreased below its carrying value. The oilfield service industry experienced an abrupt deterioration in demand during the second half of 2019, which continued into 2020. During the first quarter of 2020, the novel coronavirus (“COVID-19”) pandemic emerged and applied significant downward pressure on the global economy and oil demand and prices, leading North American operators to announce significant cuts to planned 2020 capital expenditures. The combination of the COVID-19 pandemic and supply concerns drove a steep drop in oil prices, leading to decreases in demand for the Company’s services and lower current and expected revenues for the Company.
Based on the impairment indicators above, the Company performed a goodwill and long-lived asset impairment analysis during the three months ended April 30, 2020. The results of the impairment analysis concluded that the carrying amount of the long-lived assets exceeded the relative fair values of two of the reporting units' asset groups. As a result, the Company recorded a $180.4 long-lived asset impairment charge, $39.2 related to intangible assets and $141.2 related to property and equipment, which is included in the condensed consolidated statements of operations for the nine months ended October 31, 2020. This charge reflects $91.3 and $89.1 of the long-lived assets attributable to the Southwest and Northeast/Mid-Con segments, respectively.
Determining fair value requires the use of estimates and assumptions. Such estimates and assumptions include revenue growth rates, operating profit margins, weighted average cost of capital, terminal growth rates, future market share and future market conditions, among others. The Company’s cash flow projections were a significant input into the April 30, 2020 fair values. See Note 10 for additional information regarding the fair value determination. If the Company continues to be unable to achieve projected results or long-term projections are adjusted downward, it could negatively impact future valuations of the Company’s long-lived assets.
The valuation of the Company and its reportable segments’ goodwill impairment test was estimated using the guideline public company analysis and the discounted cash flow analysis, which were equally weighted in the fair value analysis. See Note 10 for additional information regarding the fair value determination. The results of the goodwill impairment test as of April 30, 2020 indicated that goodwill was impaired because the carrying value of the Rocky Mountains reporting unit exceeded its relative fair value. Accordingly, the Company recorded a $28.3 goodwill impairment charge, which is included in the condensed consolidated statements of operations for the nine months ended October 31, 2020. This charge reflects the full value of the goodwill attributable to the Rocky Mountains segment, leaving the Company with no goodwill.
No impairment indicators were identified for the quarter ended October 31, 2021.
NOTE 8 - Accrued Liabilities
Accrued liabilities consisted of the following:
October 31, 2021
January 31, 2021
Accrued salaries, vacation and related benefits
$
16.0
$
14.3
Accrued property taxes
3.2
1.8
Accrued taxes other than property
3.2
2.6
Accrued lease termination costs
2.3
3.4
Accrued incentive compensation
0.8
1.9
Other accrued liabilities
3.2
5.2
Total accrued liabilities
$
28.7
$
29.2
NOTE 9 - Long-Term Debt
Outstanding long-term debt and capital lease obligations consisted of the following:
October 31, 2021
January 31, 2021
Notes
$
250.0
$
250.0
ABL Facility
30.0
—
Capital lease obligations
10.1
6.3
Total principal outstanding
290.1
256.3
Unamortized debt issuance costs
5.4
6.1
Total debt, net of debt issuance costs
$
284.7
$
250.2
Current portion of capital lease obligations
3.8
1.9
Long-term portion of debt and capital lease obligations
As of October 31, 2021, long-term debt consisted of $250.0 principal amount of 11.5% senior secured notes due 2025 (the “Notes”) offered pursuant to Rule 144A under the Securities Act of 1933 (as amended, the “Securities Act”) and to certain non-U.S. persons outside the United States in compliance with Regulation S under the Securities Act. On a net basis, after taking into consideration unamortized debt issuance costs for the Notes, total debt related to the Notes as of October 31, 2021 was $244.6. The Notes bear interest at an annual rate of 11.5%, payable semi-annually in arrears on May 1 and November 1. Accrued interest related to the Notes was $14.4 as of October 31, 2021.
As of October 31, 2021, the Company also had a $100.0 asset-based revolving credit facility pursuant to a senior secured credit agreement dated August 10, 2018 (the “ABL Facility”). The ABL Facility became effective on September 14, 2018 and matures in September 2023. On October 22, 2018, the ABL Facility was amended primarily to permit the Company to issue the Notes and acquire Motley Services, LLC (“Motley”) and the definition of the required ratio (as defined in the ABL Facility) was also amended as a result of the Notes issuance.
The ABL Facility is tied to a borrowing base formula and has no maintenance financial covenants as long as the minimum level of borrowing availability is maintained. The ABL Facility is secured by, among other things, a first priority lien on the Company’s accounts receivable and inventory and contains customary conditions precedent to borrowing and affirmative and negative covenants.
The ABL Facility includes a springing financial covenant which requires the Company’s consolidated fixed charge coverage ratio (“FCCR”) to be at least 1.0 to 1.0 if availability falls below the greater of $10.0 or 15% of the borrowing base. At all times during the nine months ended October 31, 2021, availability exceeded this threshold, and the Company was not subject to this financial covenant. As of October 31, 2021, the FCCR was below 1.0 to 1.0. The Company was in full compliance with its credit facility as of October 31, 2021.
Borrowings outstanding under the ABL Facility were $30.0 as of October 31, 2021 and bear interest at a rate equal to LIBOR plus the applicable margin (as defined in the ABL Facility). The effective interest rate under the ABL Facility was approximately 4.75% on October 31, 2021. Total letters of credit outstanding under the ABL Facility were $5.0 at October 31, 2021, a reduction of $1.6 or 24.2% compared to July 31, 2021. Accrued interest under the ABL Facility was $0.3 as of October 31, 2021.
Financial Services industry and market participants continue to work towards transitioning away from IBOR, including the LIBOR, that are being phased out imminently. This phasing out will have an impact on the ABL Facility that utilizes LIBOR as a benchmark. To transition from IBOR Reference Rate, the ABL Facility agreement between the Company and JP Morgan, which currently has borrowings outstanding of $30.0, will be amended to adopt an alternate rate effective on or before June 30, 2023.Until the ABL Facility agreement is amended to allow for SOFR as the replacement to LIBOR, the ABR is the default rate that JP Morgan has agreed to use as the LIBOR replacement. See Note 2 for further discussion of upcoming changes from LIBOR to Term SOFR.
We have total funds available of $40.0 and net funds available of $30.0, after $10.0 FCCR holdback, on the October 31, 2021 borrowing base certificate.
Capital Lease Obligations
The Company acquired QES's long-term capital lease agreements in the Merger. The leases are for a manufacturing and office facility supporting completion operations in Oklahoma and have 20-year lease terms. The Company also leases certain vehicles, machinery and service equipment under capital leases. The capital lease obligations for these assets have lease terms ranging from 36 months to 101 months, and the interest rates range between 3.0% to 7.2%.
Total capital lease obligations were $10.1 as of October 31, 2021, including $3.8 of current capital lease obligations.
All financial instruments are carried at amounts that approximate estimated fair value. The fair value is the price at which an asset could be exchanged in a current transaction between knowledgeable, willing parties. Assets measured at fair value are categorized based upon the lowest level of significant input to the valuations.
Level 1 – quoted prices in active markets for identical assets and liabilities.
Level 2 – quoted prices for identical assets and liabilities in markets that are not active or observable inputs other than quoted prices in active markets for identical assets and liabilities.
Level 3 – unobservable inputs in which there is little or no market data available, which require the reporting entity to develop its own assumptions.
The carrying amounts of cash and cash equivalents, accounts receivable–trade and accounts payable represent their respective fair values due to their short-term nature. The fair value of the ABL Facility approximates its carrying value as of October 31, 2021.
The following tables present the placement in the fair value hierarchy of the Notes, based on market prices for publicly traded debt, as of October 31, 2021 and January 31, 2021:
Fair value measurements at reporting date using
October 31, 2021
Level 1
Level 2
Level 3
Senior Secured Notes, 11.5 Percent Due 2025
$
143.1
$
—
$
143.1
$
—
Total Senior Secured Notes
$
143.1
$
—
$
143.1
$
—
Fair value measurements at reporting date using
January 31, 2021
Level 1
Level 2
Level 3
Senior Secured Notes, 11.5 Percent Due 2025
$
132.5
$
—
$
132.5
$
—
Total Senior Secured Notes
$
132.5
$
—
$
132.5
$
—
During the three months ended April 30, 2020, goodwill and long-lived assets, including certain property and equipment and purchased intangibles subject to amortization, were impaired as a result of the first quarter 2020 interim goodwill and long-lived asset impairment tests. The goodwill Level 3 fair value was determined using the average of the guideline public company analysis and the discounted cash flow analysis, both of which were unobservable. The long-lived asset Level 3 fair value was determined using the discounted cash flow analysis using the market and income approaches, both of which were unobservable.
Fair value is measured as of the impairment date. The carrying value and fair value of the impaired assets as of April 30, 2020 was $194.0 and $52.8 for property and equipment, net, $28.3 and nil for goodwill, and $39.2 and nil for intangible assets, net, respectively. See Note 7 for a discussion of the changes in goodwill and long-lived asset values due to impairment charges recorded during the three months ended April 30, 2020.
NOTE 11 - Commitments, Contingencies and Off-Balance-Sheet Arrangements
Lease Commitments
The Company finances its use of certain facilities and equipment under committed lease arrangements provided by various institutions. Since the terms of these arrangements meet the accounting definition of operating lease arrangements, the aggregate sum of future minimum lease payments is not reflected on the consolidated balance sheets. At October 31, 2021, future minimum lease payments under these
arrangements approximated $69.6 of which $30.1 is related to long-term real estate leases and $23.5 is related to long-term coiled tubing unit leases.
Environmental Regulations & Liabilities
The Company is subject to various federal, state and local environmental laws and regulations that establish standards and requirements for the protection of the environment. The Company continues to monitor the status of these laws and regulations. However, the Company cannot predict the future impact of such laws and regulations, as well as standards and requirements, on its business, which are subject to change and can have retroactive effectiveness. Currently, the Company has not been fined, cited or notified of any environmental violations or liabilities that would have a material adverse effect on its condensed consolidated financial statement position, results of operations, liquidity or capital resources. However, management does recognize that by the very nature of its business, material costs could be incurred in the future to maintain compliance. The amount of such future expenditures is not determinable due to several factors, including the unknown magnitude of possible regulation or liabilities, the unknown timing and extent of the corrective actions that may be required, the determination of the Company’s liability in proportion to other responsible parties and the extent to which such expenditures are recoverable from insurance or indemnification.
Litigation
The Company is at times either a plaintiff or a defendant in various legal actions arising in the normal course of business, the outcomes of which, in the opinion of management, neither individually nor in the aggregate are likely to result in a material adverse effect on the Company’s condensed consolidated financial statements.
On March 9, 2021, the Company filed claims in the District Court of Harris County, Texas against Magellan E&P Holdings, Inc. ("Magellan"), Redmon-Keys Insurance Group, Inc. and certain underwriters at Lloyd's ("Underwriters") to recover $4.6 owed on invoices duly issued by the Company for services rendered on behalf of the defendants in response to an offshore well blowout near Bob Hall Pier in Corpus Christi, Texas. Magellan did not dispute the invoices but alleged an inability to pay prior to obtaining funding from Underwriters under Magellan's Owner's Extra Expense Policy. On March 19, 2021, Underwriters filed a declaratory judgment action in the United States District Court for the Southern District of Texas seeking a declaration that certain blowout related expenses fall outside of policy coverage. On March 30, 2021, Magellan filed for bankruptcy pursuant to Chapter 7 of the U.S. bankruptcy code. The bankruptcy proceedings are ongoing. We expect that the trustee will continue to pursue claims against Underwriters as well as preference and other claims to maximize the value of the Chapter 7 estate for the benefit of trade creditors. During the year ended January 31, 2021, the Company reserved the full amount of its invoices totaling $4.6 as a prudent action in light of the Chapter 7 filing.
Indemnities, Commitments and Guarantees
During its ordinary course of business, the Company has made certain indemnities, commitments and guarantees under which it 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, as well as 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 the Company could be obligated to make. However, the Company is unable to estimate the maximum amount of liability related to its indemnities, commitments and guarantees because such liabilities are contingent upon the occurrence of events that are not reasonably determinable. Management believes that any liability for these indemnities, commitments and guarantees would not be material to the accompanying condensed consolidated financial statements. Accordingly, no significant amounts have been accrued for indemnities, commitments and guarantees.
On June 14, 2021, the Company entered into an Equity Distribution Agreement (the “Equity Distribution Agreement”) with Piper Sandler & Co. as sales agent (the “Agent”). Pursuant to the terms of the Equity Distribution Agreement, the Company may sell from time to time through the Agent (the “Offering”) the Company’s common stock, par value $0.01 per share, having an aggregate offering price of up to $50.0 (the “Common Stock”).
Any Common Stock offered and sold in the Offering will be issued pursuant to the Company’s shelf registration statement on Form S-3 (Registration No. 333-256149) filed with the SEC on May 14, 2021 and declared effective on June 11, 2021 (the “Registration Statement”), the prospectus supplement relating to the Offering filed with the SEC on June 14, 2021 and any applicable additional prospectus supplements related to the Offering that form a part of the Registration Statement. Sales of Common Stock under the Equity Distribution Agreement may be made in any transactions that are deemed to be “at the market offerings” as defined in Rule 415 under the Securities Act of 1933, as amended (the “Securities Act”).
The Equity Distribution Agreement contains customary representations, warranties and agreements by the Company, indemnification obligations of the Company and the Agent, including for liabilities under the Securities Act, other obligations of the parties and termination provisions. Under the terms of the Equity Distribution Agreement, the Company will pay the Agent a commission equal to 3.0% of the gross sales price of the Common Stock sold.
The Company plans to use the net proceeds from the Offering, after deducting the Agent’s commissions and the Company’s offering expenses, for general corporate purposes, which may include, among other things, paying or refinancing all or a portion of the Company’s then-outstanding indebtedness, and funding acquisitions, capital expenditures and working capital.
During the three and nine months ended October 31, 2021, the Company sold 1,070,000 and 1,130,216 shares of Common Stock, respectively, for gross proceeds of approximately $4.9 and $5.5, respectively, and paid legal and administrative fees of $0.1 and $0.7, respectively.
Stock-Based Compensation
The Company has a Long-Term Incentive Plan (“LTIP”) under which the compensation committee of the Board (the “Compensation Committee”) has the authority to grant stock options, stock appreciation rights, restricted stock, restricted stock units or other forms of equity-based or equity-related awards. Compensation cost for the LTIP grants is generally recorded on a straight-line basis over the vesting term of the shares based on the grant date value using the closing trading price.
On February 12, 2021, the stockholders of KLXE approved the KLX Energy Services Holdings, Inc. Long-Term Incentive Plan (Amended and Restated as of December 2, 2020) (the “Amended and Restated LTIP”), which, among other things, increased the total number of shares of Company Common Stock, par value $0.01 per share, and reserved for issuance under the Amended and Restated LTIP by 632,051 shares. A description of the Amended and Restated LTIP is included in the Company’s proxy statement, filed with the SEC on January 11, 2021.
Compensation cost recognized during the three and nine months ended October 31, 2021 and 2020 was related to grants of restricted stock as approved by the Compensation Committee. Certain grants of restricted stock to directors and management accelerated in connection with the Merger on July 28, 2020, resulting in approximately $15.1 of stock-based compensation expense during the nine months ended October 31, 2020. Stock-based compensation was $0.9 and $0.5 for the three months ended October 31, 2021 and 2020, respectively, and $2.7 and $17.2 for the nine months ended October 31, 2021 and 2020, respectively. Unrecognized compensation cost related to restricted stock awards made by the Company was $7.1 at October 31, 2021.
As of the date of the QES acquisition, each unvested QES restricted stock unit award was converted into a replacement 0.0969 KLXE restricted stock unit award. Approximately 2.0 million shares of QES common stock subject to awards outstanding were converted to 0.2 million shares of common stock assumed by KLXE.
NOTE 13 - Income Taxes
Income tax expense was $0.2 and $0.4 for the three and nine months ended October 31, 2021, respectively, and was comprised primarily of state and local taxes, compared to $0.2 and $0.3 for the three and nine months ended October 31, 2020, respectively. The Company has a valuation allowance against its deferred tax balances, and as a result, it was unable to recognize a tax benefit on its year-to-date losses.
In response to the COVID-19 pandemic, many governments have enacted or are contemplating measures to provide aid and economic stimulus. These measures may include deferring the due dates of tax payments or other changes to their income and non-income-based tax laws. The Coronavirus Aid, Relief, and Economic Security Act (“CARES Act”), which was enacted on March 27, 2020 in the United States, includes measures to assist companies. Under the CARES Act, the Company has deferred the employer portion of FICA tax payments of $3.8 as of October 31, 2021. This deferral is included on the condensed consolidated balance sheet. Accrued and other non-current liabilities each had a balance of $1.9 as of October 31, 2021. These payments are due in two installments: half on December 31, 2021 and half on December 31, 2022.
The American Rescue Plan Act of 2021 (the "ARP”) enacted on March 11, 2021 in the United States, responds to the continued economic and health impacts of the COVID-19 pandemic. The ARP includes a wide variety of tax and non-tax provisions. The Company does not anticipate any material impacts from this legislation.
The Company continues to monitor additional guidance issued by the U.S. Treasury Department, the Internal Revenue Service and others.
NOTE 14 - Segment Reporting
The Company is organized on a geographic basis. The Company’s reportable segments, which are also its operating segments, are comprised of the Southwest Region (the Permian Basin and the Eagle Ford Shale), the Rocky Mountains Region (the Bakken, Williston, DJ, Uinta, Powder River, Piceance and Niobrara basins) and the Northeast/Mid-Con Region (the Marcellus and Utica Shale as well as the Mid-Continent STACK and SCOOP and Haynesville Shale). The segments regularly report their results of operations and make requests for capital expenditures and acquisition funding to the CODM. As a result, the Company has three reportable segments.
The following table presents revenues and operating loss by reportable segment:
Three Months Ended
Nine Months Ended
October 31, 2021
October 31, 2020
October 31, 2021
October 31, 2020
Revenues
Rocky Mountains
$
36.5
$
18.2
$
94.4
$
70.1
Southwest
45.8
24.8
126.8
53.4
Northeast/Mid-Con
56.7
27.9
120.5
66.6
Total revenues
139.0
70.9
341.7
190.1
Operating loss (1)(2)
Rocky Mountains
(1.7)
(4.6)
(11.1)
(45.3)
Southwest
(4.1)
(9.3)
(15.3)
(114.6)
Northeast/Mid-Con
1.7
(5.1)
(8.9)
(105.2)
Corporate and other (1)
(6.3)
(11.4)
(20.9)
(13.7)
Total operating loss(3)
(10.4)
(30.4)
(56.2)
(278.8)
Interest expense, net
8.2
7.7
24.0
22.7
Loss before income tax
$
(18.6)
$
(38.1)
$
(80.2)
$
(301.5)
(1) Historically, and through July 31, 2020, the Company’s total corporate overhead costs were allocated and reported within each reportable segment. During the third quarter of 2020, the Company changed the corporate overhead allocation methodology to include corporate costs incurred on behalf of its operating segments, which includes accounts payable, accounts receivable, insurance, audit, supply chain, health, safety and environmental and others. The remaining unallocated corporate costs are reported as a reconciling item. The change will better reflect the CODM’s philosophy on assessing performance and allocating resources, as well as improve comparability to the Company’s peer group.
(2)Operating loss for the three and nine months ended October 31, 2020 includes impairment and other charges of $4.4 and $213.1, respectively, of which $1.6 and $92.9, respectively, were attributable to the Southwest segment, $0.0 and $28.3, respectively, were attributable to the Rocky Mountains segment, $0.5 and $89.6, respectively, were attributable to the Northeast/Mid-Con segment and $2.3 and $2.3, respectively, were attributable to Corporate and other.
(3) Includes reduction in bargain purchase gain of $2.4 and bargain purchase gain of $38.7 during the three and nine-month periods ending October 31, 2020, respectively.
The following tables present revenues by service offering by reportable segment:
The following table presents capital expenditures by reportable segment:
Three Months Ended
Nine Months Ended
October 31, 2021
October 31, 2020
October 31, 2021
October 31, 2020
Rocky Mountains
$
0.4
$
0.9
$
2.3
$
4.3
Southwest
0.7
0.8
2.6
3.0
Northeast/Mid-Con
0.7
0.6
2.5
2.2
Corporate and other
—
0.3
0.1
1.6
Total capital expenditures
$
1.8
$
2.6
$
7.5
$
11.1
The following table presents total assets by segment:
October 31, 2021
January 31, 2021
Rocky Mountains
$
115.0
$
121.1
Southwest
117.8
91.6
Northeast/Mid-Con
78.5
98.1
Total segment assets
311.3
310.8
Corporate and other
43.5
51.9
Total assets
$
354.8
$
362.7
NOTE 15 - Net Loss Per Common Share
Basic net loss per common share is computed using the weighted average common shares outstanding during the period. Diluted net loss per common share is computed by using the weighted average common shares outstanding, including the dilutive effect of restricted shares based on an average share price during the period. For the three months ended October 31, 2021 and 2020, 0.5 and 0.3 million shares of the Company’s common stock, respectively, and for the nine months ended October 31, 2021 and 2020, 0.4 and 0.5 million shares of the Company’s common stock, respectively, were excluded from the determination of diluted net loss per common share because their effect would have been anti-dilutive. The computations of basic and diluted net loss per share for the three and nine months ended October 31, 2021 and 2020 are as follows:
The Private Securities Litigation Reform Act of 1995 provides a “safe harbor” for forward-looking statements to encourage companies to provide prospective information to investors. This Quarterly Report on Form 10-Q (this “Quarterly Report”) includes forward-looking statements that reflect our current expectations and projections about our future results, performance and prospects. Forward-looking statements include all statements that are not historical in nature or are not current facts. When used in this Quarterly Report, the words “believe,” “expect,” “plan,” “intend,” “anticipate,” “estimate,” “predict,” “potential,” “continue,” “may,” “might,” “should,” “could,” “will” or the negative of these terms or similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on our current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events.
These forward-looking statements are subject to a number of risks, uncertainties, assumptions and other factors that could cause our actual results, performance and prospects to differ materially from those expressed in, or implied by, these forward-looking statements. Factors that might cause such a difference include those discussed in our filings with the SEC, in particular those discussed under the headings “Risk Factors” in our Annual Report on Form 10-K for the fiscal year ended January 31, 2021 and in this Quarterly Report, including the following factors:
•the extraordinary market environment and impacts resulting from the COVID-19 pandemic and related swift and material decline, as well as increased volatility, in national and global crude oil demand and crude oil prices;
•the possibility of inefficiencies, curtailments or shutdowns in our customers’ operations, whether due to COVID-19 repercussions in the workforce or in response to reductions in demand;
•regulation of and dependence upon the energy industry;
•the cyclical nature of the energy industry;
•fluctuations in market prices for fuel, oil and natural gas;
•our ability to maintain acceptable pricing for our services;
•competitive conditions within the industry;
•the loss of or interruption in operations of one or more key suppliers;
•legislative or regulatory changes and potential liability under federal and state laws and regulations;
•decreases in the rate at which oil and/or natural gas reserves are discovered and/or developed;
•the impact of technological advances on the demand for our products and services;
•customers' delays in obtaining permits for their operations;
•hazards and operational risks that may not be fully covered by insurance;
•the write-off of a significant portion of intangible assets;
•the need to obtain additional capital or financing, and the availability and/or cost of obtaining such capital or financing;
•limitations originating from our organizational documents, debt instruments and U.S. federal income tax obligations may have on our financial flexibility, our ability to engage in strategic transactions or our ability to declare and pay cash dividends on our common stock;
•general economic conditions;
•our credit profile;
•changes in supply, demand and costs of equipment;
•oilfield anti-indemnity provisions;
•seasonal and adverse weather conditions that can affect oil and natural gas operations;
•reliance on information technology resources and the inability to implement new technology and services;
•the possibility of terrorist or cyberattacks and the consequences of any such attacks;
•increased labor costs or our ability to employ, or maintain the employment of, a sufficient number of key employees, technical personnel, and other skilled and qualified workers;
•the inability to successfully consummate acquisitions or inability to manage potential growth; and
•our ability to remediate any material weakness in, or to maintain effective, internal controls over financial reporting and disclosure controls and procedures.
In light of these risks and uncertainties, you are cautioned not to put undue reliance on any forward-looking statements in this Quarterly Report. These statements should be considered only after carefully reading this entire Quarterly Report. Except as required under the federal securities laws and rules and regulations of the SEC, we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. Additional risks that we may currently deem immaterial or that are not presently known to us could also cause the forward-looking events discussed in this Quarterly Report not to occur.
All forward-looking statements, expressed or implied, included in this Quarterly Report are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statement that we or persons acting on our behalf may issue.
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (In millions of U.S. dollars and shares)
The following discussion and analysis should be read in conjunction with the historical condensed consolidated financial statements and related notes included elsewhere in this Quarterly Report on Form 10-Q (“Quarterly Report”) as well as our Annual Report on Form 10-K for the fiscal year ended January 31, 2021. This discussion contains forward-looking statements reflecting our current expectations and estimates and assumptions concerning events and financial trends that may affect our future operating results or financial position. Actual results and the timing of events may differ materially from those contained in these forward-looking statements due to a number of factors, including those discussed in the sections entitled “Risk Factors” and “Cautionary Statement Regarding Forward-Looking Statements” appearing elsewhere in this Quarterly Report.
The following discussion and analysis addresses the results of KLX Energy Services Holdings, Inc.’s (the “Company”, “KLXE” or “KLX Energy Services”) operations for the three and nine months ended October 31, 2021, as compared to our results of operations for the three and nine months ended October 31, 2020. In addition, the discussion and analysis addresses our liquidity, financial condition and other matters for these periods. The previously announced merger of Krypton Merger Sub, Inc., an indirect wholly owned subsidiary of KLXE ("Merger Sub"), with and into QES, with QES surviving the merger as a subsidiary of KLXE (the "Merger") closed on July 28, 2020. Unless otherwise noted or the context requires otherwise, references herein to KLX Energy Services with respect to time periods prior to July 28, 2020 include KLX Energy Services and its consolidated subsidiaries and do not include QES and its consolidated subsidiaries, while references herein to KLX Energy Services with respect to time periods from and after July 28, 2020 include QES and its consolidated subsidiaries.
Company History
KLX Energy Services was initially formed from the combination of seven private oilfield service companies acquired during 2013 and 2014. Each of the acquired businesses was regional in nature and brought one or two specific service capabilities to KLX Energy Services. Once the acquisitions were completed, we undertook a comprehensive integration of these businesses to align our services, our people and our assets across all the geographic regions where we maintain a presence. In November 2018, we expanded our completion and intervention service offerings through the acquisition of Motley Services, LLC (“Motley”), a premier provider of large diameter coiled tubing services, further enhancing our completions business. We successfully completed the integration of the Motley business during fiscal 2018. On March 15, 2019, the Company acquired Tecton Energy Services (“Tecton”), a leading provider of flowback, drill-out and production testing services, operating primarily in the greater Rocky Mountains. In March 2019, the Company acquired Red Bone Services LLC (“Red Bone”), a premier provider of oilfield services primarily in the Mid-Continent region, providing fishing, non-hydraulic fracturing high-pressure pumping, thru-tubing and certain other services. We successfully completed the integration of the Tecton and Red Bone businesses during fiscal 2019. We acquired QES during the second quarter of 2020 and, by doing so, helped establish KLXE as an industry leading provider of diversified oilfield solutions across the full well lifecycle to the major onshore oil and gas producing regions of the United States.
On July 26, 2020, the Company’s Board of Directors (the "Board") approved a 1-for-5 Reverse Stock Split. On July 28, 2020, we successfully completed the all-stock Merger with QES. At the time of the closing, the holders of QES common stock received 0.0969 shares of KLXE common stock in exchange for each share of QES common stock held. KLXE and QES stockholders owned approximately 59% and 41%, respectively, of the equity of the combined company on a fully-diluted basis.
The Merger of KLXE and QES provided increased scale to serve a blue-chip customer base across the onshore oil and gas basins in the United States. The Merger combined two strong company cultures comprised of highly talented teams with shared commitments to safety, performance, customer service and profitability. The combination leveraged two of the largest fleets of coiled tubing and wireline assets, and
KLXE became a leading provider of large diameter coiled tubing and wireline services and one of the largest independent providers of directional drilling to the U.S. market.
After closing the Merger, the Company focused on integrating personnel, facilities, processes and systems across all functional areas of the organization.
By the end of first quarter of 2021, the Company had implemented approximately $46.0 of annualized cost savings. We continue to be diligently focused on generating additional cost savings from the Merger and to date have realized such savings through eliminating KLXE's legacy corporate headquarters in Wellington, Florida, rationalizing associated corporate functions to Houston, and capturing operational synergies in the areas of personnel, facilities and rolling stock.
During the first quarter of 2021, we consolidated corporate offices in Houston, Texas and identified $4.4 of additional annualized fixed cost savings associated with headcount, facilities, changes to management processes and reduction in the size of the Board from nine directors to seven directors. These cost savings were fully implemented by the end of the second quarter and were completely realized during the third quarter.
Additional synergies may be realized as management continues to rationalize operational facilities and align common roles, processes and systems throughout each function and region. The Merger also enhances the Company’s ability to effect further industry consolidation. Looking ahead, the Company expects to pursue strategic, accretive consolidation opportunities that further strengthen the Company’s competitive positioning and capital structure and drive efficiencies, accelerate growth and create long‑term stockholder value.
Company Overview
We serve many of the leading companies engaged in the exploration and development of onshore conventional and unconventional oil and natural gas reserves in the United States. Our customers are primarily large independent and major oil and gas companies. We currently support these customer operations from over 50 service facilities located in the key major basins. We operate in three segments on a geographic basis, including the Southwest Region (the Permian Basin, Eagle Ford Shale and the Gulf Coast including industrial and petrochemical facilities), the Rocky Mountains Region (the Bakken, Williston, DJ, Uinta, Powder River, Piceance and Niobrara basins) and the Northeast/Mid-Con Region (the Marcellus and Utica Shale as well as the Mid-Continent STACK and SCOOP and Haynesville Shale). Our revenues, operating earnings and identifiable assets are primarily attributable to these three reportable geographic segments. While we manage our business based upon these geographic groupings, our assets and our technical personnel are deployed on a dynamic basis across all of our service facilities to optimize utilization and profitability.
These expansive operating areas provide us with access to a number of nearby unconventional crude oil and natural gas basins, both with existing customers expanding their production footprint and third parties acquiring new acreage. Our proximity to existing and prospective customer activities allows us to anticipate or respond quickly to such customers’ needs and efficiently deploy our assets. We believe that our strategic geographic positioning will benefit us as activity increases in our core operating areas. Our broad geographic footprint provides us with exposure to the ongoing recovery in drilling, completion, production and intervention related service activity and will allow us to opportunistically pursue new business in basins with the most active drilling environments.
We work with our customers to provide engineered solutions across the lifecycle of the well by streamlining operations, reducing non-productive time and developing cost effective solutions and customized tools for our customers’ challenging service needs, including their most technically complex extended reach horizontal wells. We believe future revenue growth opportunities will continue to be driven by increases in the number of new customers served and the breadth of services we offer to existing and prospective customers.
We offer a variety of targeted services that are differentiated by the technical competence and experience of our field service engineers and their deployment of a broad portfolio of specialized tools and proprietary equipment. Our innovative and adaptive approach to proprietary tool design has been employed by our in-house research and development organization and, in selected instances, by our technology partners to develop tools covered by 28 patents and 7 pending patent applications, which we believe differentiates us from our regional competitors and also allows us to deliver more focused service and better outcomes in our specialized services than larger national competitors that do not discretely dedicate their resources to the services we provide.
We utilize contract manufacturers to produce our products, which, in many cases, our engineers have developed from input and requests from our customers and customer-facing managers, thereby maintaining the integrity of our intellectual property while avoiding manufacturing startup and maintenance costs. This approach leverages our technical strengths, as well as those of our technology partners. These services and related products are modest in cost to the customer relative to other well construction expenditures but have a high cost of failure and are, therefore, mission critical to our customers’ outcomes. We believe our customers have come to depend on our decades of field experience to execute on some of the most challenging problems they face. We believe we are well positioned as a company to service customers when they are drilling and completing complex wells, and remediating both newer and older legacy wells.
We invest in innovative technology and equipment designed for modern production techniques that increase efficiencies and production for our customers. North American unconventional onshore wells are increasingly characterized by extended lateral lengths, tighter spacing between hydraulic fracturing stages, increased cluster density and heightened proppant loads. Drilling and completion activities for wells in unconventional resource plays are extremely complex, and downhole challenges and operating costs increase as the complexity and lateral length of these wells increase. For these reasons, exploration and production ("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 technically complex wells where the potential for increased operating leverage is high due to the large number of stages per well.
We endeavor to continue to build 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 research and development team.
Depreciation and Amortization
The Company changed its presentation of depreciation and amortization expense in the first quarter of 2021. Depreciation and amortization expense is presented separately from cost of sales and selling, general, and administrative expenses. Prior period results have been reclassified to conform with current presentation.
During the quarter, as a result of increased usage from improving drilling activity levels and changes in the manner and conditions in which various types of our small tools are used, we updated the estimated useful lives of such tools to 1 - 3 years, resulting in approximately $0.2 of incremental monthly depreciation on a prospective basis.
Segment Reporting
During the third quarter of 2020, the Company changed its presentation of reportable segments related to the allocation of corporate overhead costs to reflect the presentation used by the Company's chief operational decision-making group ("CODM") to make decisions about resources to be allocated to the Company’s reportable segments and to assess segment performance. Historically, and through July 31, 2020, the
Company’s total corporate overhead costs were allocated and reported within each reportable segment. Starting in the third quarter of 2020, the Company changed the corporate overhead allocation methodology to only include corporate costs incurred on behalf of its operating segments, which includes accounts payable, accounts receivable, insurance, audit, supply chain, health, safety and environmental and others. The remaining unallocated corporate costs are reported as a reconciling item in the Company’s segment reporting disclosures. See Note 14 to the condensed consolidated financial statements for additional information. As a result of the change in presentation, the total corporate overhead costs allocated for the three and nine months ended October 31, 2020 to the Company’s three reportable segments decreased by $11.4 and $13.7, respectively.
The Company also changed its presentation of service offering revenues. Historically, and through January 31, 2020, the Company’s service offering revenues included revenues from the completion, production and intervention market types within segment reporting. During the third quarter of 2020, the Company changed the presentation of its service offering revenues by separately reporting a drilling market type revenue, which includes directional drilling, drilling accommodation units and related drilling support services. The reclassifications are retroactively reported in the Company’s segment reporting disclosures to reflect the drilling revenue change and use of the information by the Company’s CODM.
These changes in the Company’s corporate allocation method and service offering revenue disclosures have no net impact to the condensed consolidated financial statements. The change better reflects the CODM’s philosophy on assessing performance and allocating resources as well as improves the Company’s comparability to its peer group.
On September 3, 2021, the Board of the Company adopted the Fourth Amended and Restated Bylaws of the Company, effective as of such date, to change the Company’s fiscal year-end from January 31 to December 31, effective beginning with the year ended December 31, 2021. As a result, the Company’s current fiscal year 2021 will be shortened from 12 months to 11 months and end on December 31, 2021. The Company is undertaking this change in an effort to normalize our fiscal year-end and improve comparability with our peers.
Recent Trends and Outlook
Demand for services in the oil and natural gas industry is cyclical and subject to sudden and significant volatility. Market demand for our services during 2020 was challenged due to the novel coronavirus ("COVID-19") pandemic and macro supply and demand concerns. While the extent and duration of the continued global impact of the COVID-19 pandemic is unknown, economic activity has increased from the April 2020 lows, and signs of a potential global economic recovery in fiscal 2021 have emerged, driven by the rollout of COVID-19 vaccines, fiscal and monetary stimulus policies, and pent-up demand for goods and services.
Despite the market headwinds experienced in 2020, the Company remained focused on building a leaner and more profitable set of service offerings, which allowed us to make meaningful positive impacts to our revenue, operating margins, cash flows and Adjusted EBITDA. See "How We Evaluate Our Operations" for additional information. We have taken, and are continuing to take, steps to reduce costs, including reductions in capital expenditures, as well as other workforce rightsizing and ongoing streamlining initiatives.
In February of 2021, we experienced a material slow down due to the unprecedented Winter Storm Uri, the costliest winter storm in U.S. history. As a result of the storm conditions, our customers shut-in wells and delayed work, causing us at least seven days of lost revenue, primarily in the Permian and the Mid-continent regions.
So far in fiscal 2021, West Texas Intermediate ("WTI") prices have increased an incremental 16.4% from May 1 to July 31 and another 12.9% from July 31 to October 31. In response, the United States has continued to increase drilling and completion activity levels relative to where the market exited 2020. As of October 31, 2021, U.S. rig count was up to 544, an increase of 11.5% since July 31, 2021. Additionally, we
have continued to see U.S. shale operators consolidate within certain basins, particularly the Permian and Rocky Mountains, and many public operators have announced that they are targeting oil and gas production at the end of 2021 to be consistent with production levels at year end 2020.
We saw a meaningful increase in overall activity throughout the first three quarters of 2021, as commodity prices have reached levels last seen in 2014. Looking ahead to the remainder of fiscal 2021, provided that the impact of the COVID-19 pandemic lessens, economic activity continues to increase, and commodity prices remain strong, we expect to experience further increases in activity and corresponding improvements in the price of our products and services.
We believe our diverse product and service offerings uniquely positions KLXE to respond to a rapidly evolving marketplace where we can provide a comprehensive suite of engineered solutions for our customers with one call and one master services agreement.
How We Generate Revenue and the Costs of Conducting Our Business
Our business strategy seeks to generate attractive returns on capital by providing differentiated services and prudently applying our cash flow to select targeted opportunities, with the potential to deliver high returns that we believe offer superior margins over the long-term and short payback periods. Our services generally require equipment that is less expensive to maintain and is operated by a smaller staff than many other oilfield service providers. As part of our returns-focused approach to capital spending, we are focused on efficiently utilizing capital to develop new products. We support our existing asset base with targeted investments in research and development, which we believe allows us to maintain a technical advantage over our competitors providing similar services using standard equipment.
Demand for services in the oil and natural gas industry is cyclical and subject to sudden and significant volatility. We remain focused on serving the needs of our customers by providing a broad portfolio of product service lines across all major basins, while preserving a solid balance sheet, maintaining sufficient operating liquidity and prudently managing our capital expenditures.
We believe our operating cost structure is now materially lower than during historical financial reporting periods and the realization of the $50.4 of cost synergies associated with the Merger has further reduced our cost structure and afforded us greater flexibility to respond to changing industry conditions. The implementation of integrated, company-wide management information systems and processes provides more transparency to current operating performance and trends within each market where we compete and helps us more acutely scale our cost structure and pricing strategies on a market-by-market basis. The potential for further cost savings remains as we continue to refine and optimize the business moving forward. We believe our ability to differentiate ourselves on the basis of quality provides an opportunity for us to gain market share and increase our share of business with existing customers.
We believe we have strong management systems in place which will allow us to manage our operating resources and associated expenses relative to market conditions. Historically, we believe our services generated margins superior to our competitors based upon the differential quality of our performance, and that these margins would contribute to future cash flow generation. The required investment in our business includes both working capital (principally for accounts receivable, inventory and accounts payable growth tied to increasing activity) and capital expenditures for both maintenance of existing assets and ultimately growth when economic returns justify the spending. Our required maintenance capital expenditures tend to be lower than other oilfield service providers due to the generally asset-light nature of our services, the younger average age of our assets and our ability to charge back a portion of asset maintenance to customers for a number of our assets.
We recognize the highly cyclical nature of our business and the need for metrics to (1) best measure the trends in our operations and (2) provide baselines and targets to assess the performance of our managers.
The measures we believe most effective to achieve the above stated goals include:
•Revenue
•Adjusted Earnings before interest, taxes, depreciation and amortization ("Adjusted EBITDA"): Adjusted EBITDA is a supplemental non-Generally Accepted Accounting Principles financial measure that is used by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies. Adjusted EBITDA is not a measure of net earnings or cash flows as determined by Generally Accepted Accounting Principles ("GAAP"). We define Adjusted EBITDA as net earnings (loss) before interest, taxes, depreciation and amortization, further adjusted for (i) goodwill and/or long-lived asset impairment charges, (ii) stock-based compensation expense, (iii) restructuring charges, (iv) transaction and integration costs related to acquisitions and (v) other expenses or charges to exclude certain items that we believe are not reflective of ongoing performance of our business.
•Adjusted EBITDA Margin: Adjusted EBITDA Margin is defined as Adjusted EBITDA, as defined above, as a percentage of revenue.
We believe Adjusted EBITDA is useful because it allows us to supplement the GAAP measures in order to evaluate our operating performance and compare the results of our operations from period to period without regard to our financing methods or capital structure. We exclude the items listed above in arriving at Adjusted EBITDA (Loss) because these amounts can vary substantially from company to company within our industry depending upon accounting methods, book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDA should not be considered as an alternative to, or more meaningful than, net (loss) earnings as determined in accordance with GAAP, or as an indicator of our operating performance or liquidity. Certain items excluded from Adjusted EBITDA are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of Adjusted EBITDA. Our computations of Adjusted EBITDA may not be comparable to other similarly titled measures of other companies.
Three Months Ended October 31, 2021 Compared to Three Months Ended October 31, 2020
Revenue.The following is a summary of revenue by segment:
Three Months Ended
October 31, 2021
October 31, 2020
% Change
Revenue:
Rocky Mountains
$
36.5
$
18.2
100.5
%
Southwest
45.8
24.8
84.7
%
Northeast/Mid-Con
56.7
27.9
103.2
%
Total revenue
$
139.0
$
70.9
96.1
%
For the quarter ended October 31, 2021, revenues were $139.0, an increase of $68.1, or 96.1%, as compared with the prior year period. Rocky Mountains segment revenue increased by $18.3, or 100.5%, Southwest segment revenue increased $21.0, or 84.7%, and Northeast/Mid-Con segment revenue increased by $28.8, or 103.2%. The increases in all three operating segments were driven by a combination of increased pricing for the Company's products and services as well as increased activity. In the current quarter, rig count increased to 544, by 248 or 84% as compared to the same period of the prior year. This was driven by an increase in production activity across all three of our operating segments. Additionally, pricing has increased materially across most of our product service lines as compared to the same period of the prior year.
On a product line basis, drilling, completion, production and intervention services contributed approximately 27.8%, 48.8%, 14.0% and 9.4%, respectively, to revenue for the three months ended October 31, 2021 and 21.6%, 43.9%, 10.6% and 24.0%, respectively, for the three months ended October 31, 2020. The most significant contribution to the increase came from drilling, which increased by $23.4, or 152.9%, due to the directional drilling service revenues acquired in the Merger with QES. Completion, production and intervention services revenues changed by approximately $36.6 or 117.7%, $12.0 or 160.0% and $(3.9) or (22.9)%, respectively, as compared to the same period in the prior year.
Cost of sales. For the quarter ended October 31, 2021, cost of sales were $120.7, or 86.8% of revenues, as compared to the prior year period of $65.6, or 92.5% of revenues. Cost of sales as a percentage of revenues decreased primarily due to the improvement in pricing discussed above, which has more than offset cost pressures related to labor and supply chain.
Selling, general and administrative expenses. For the quarter ended October 31, 2021, selling, general and administrative (“SG&A”) expenses were $14.8, or 10.6% of revenues, as compared with $14.1, or 19.9% of revenues, in the prior year period. Decrease in SG&A as a percentage of revenues was driven primarily by the improvement in pricing discussed above. Additionally, SG&A expenses for the quarter ended October 31, 2020, included $2.7 of merger and integration costs.
Operating loss. The following is a summary of operating income (loss) by segment:
Three Months Ended
October 31, 2021
October 31, 2020
% Change
Operating loss:
Rocky Mountains
$
(1.7)
$
(4.6)
63.0
%
Southwest
(4.1)
(9.3)
55.9
%
Northeast/Mid-Con
1.7
(5.1)
133.3
%
Corporate and other(1)
(6.3)
(11.4)
44.7
%
Total operating loss(1)
$
(10.4)
$
(30.4)
65.8
%
(1) Includes reduction in bargain purchase gain of $2.4 during the three months ended October 31, 2020.
For the quarter ended October 31, 2021, operating loss was $10.4 compared to operating loss of $30.4 in the prior year period, due to above increases in activity and improvements in pricing, along with synergies implemented related to integration of the Merger and consolidating operating facilities and headcount. Additionally, operating loss for Corporate and other for the quarter ended October 31, 2020 includes $2.4 of a non-recurring reduction in bargain purchase gain.
Results improved in all segments compared to prior year period, as Rocky Mountains segment operating loss was $1.7, Southwest segment operating loss was $4.1, and Northeast/Mid-Con segment operating income was $1.7 for the three months ended October 31, 2021, in each case primarily driven by increased activity due to higher rig count, improved pricing, and a reduced cost structure driven by successful integration of the QES business.
Income tax expense. For the quarter ended October 31, 2021, income tax expense was $0.2, which was consistent with the prior year period, and was comprised primarily of state and local taxes. The Company did not recognize a tax benefit on its year-to-date losses because it has a valuation allowance against its deferred tax balances, which prevents the Company from recording such benefit.
Net loss. For the quarter ended October 31, 2021, net loss was $18.8, as compared to $38.3 in the prior year period, due to above-mentioned increase in activity as well as improvements in pricing.
Results of Operations
Nine Months Ended October 31, 2021 Compared to Nine Months Ended October 31, 2020
Revenue.The following is a summary of revenue by segment:
Nine Months Ended
October 31, 2021
October 31, 2020
% Change
Revenue:
Rocky Mountains
$
94.4
$
70.1
34.7
%
Southwest
126.8
53.4
137.5
%
Northeast/Mid-Con
120.5
66.6
80.9
%
Total revenue
$
341.7
$
190.1
79.7
%
For the nine months ended October 31, 2021, revenues were $341.7, an increase of $151.6, or 79.7%, as compared with the prior year period. Rocky Mountains segment revenue increased by $24.3, or 34.7%, Southwest segment revenue increased $73.4, or 137.5%, and Northeast/Mid-Con segment revenue increased by $53.9, or 80.9%. The increases in all three operating segments were driven by a combination of increased pricing for the Company's products and services as well as increased activity. In the current quarter, rig count increased to 544, by 248 or 84% as compared to the same period of the prior year. This was driven by an increase in production activity across all three of our operating segments. Additionally, pricing has increased materially across most of our product service lines as compared to the same period of the prior year.
On a product line basis, drilling, completion, production and intervention services contributed approximately 27.9%, 47.9%, 14.1% and 10.1%, respectively, to revenue for the nine months ended October 31, 2021 and 14.2%, 48.6%, 14.3% and 22.9%, respectively, for the nine months ended October 31, 2020. The most significant contribution to the increase came from drilling, which increased by $68.5, or 254.6%, due to the directional drilling service revenues acquired in the Merger with QES. Completion, production, and intervention services revenues changed by approximately $71.4 or 77.3%, $20.9 or 76.8% and $(9.2) or (21.1)%, respectively, as compared to the same period in the prior year.
Cost of sales. For the nine months ended October 31, 2021, cost of sales were $308.5, or 90.3% of revenues, as compared to the prior year period of $180.5, or 95.0% of revenues. Cost of sales as a
percentage of revenues decreased primarily due to the improvement in pricing discussed above, which has more than offset cost pressures related to labor and supply chain.
Selling, general and administrative expenses. For the nine months ended October 31, 2021, SG&A expenses were $44.1, or 12.9% of revenues, as compared with $69.6, or 36.6% of revenues, in the prior year period. Decreases in SG&A expense and SG&A as a percentage of revenues were driven by the improvement in pricing discussed above. Additionally, SG&A expenses for the nine months ended October 31, 2020, included $28.9 of merger and integration costs.
Operating loss. The following is a summary of operating loss by segment:
Nine Months Ended
October 31, 2021
October 31, 2020
% Change
Operating loss:
Rocky Mountains
$
(11.1)
$
(45.3)
75.5
%
Southwest
(15.3)
(114.6)
86.6
%
Northeast/Mid-Con
(8.9)
(105.2)
91.5
%
Corporate and other
(20.9)
(13.7)
(52.6)
%
Total operating loss(1)
$
(56.2)
$
(278.8)
79.8
%
(1) Includes bargain purchase gain of $38.7 during the nine months ended October 31, 2020.
For the nine months ended October 31, 2021, operating loss was $56.2 compared to operating loss of $278.8 in the prior year period, due to a decrease in impairment and other charges from $213.1 in 2020 to $0.8 in 2021, as well as due to above increases in activity and improvements in pricing, along with synergies implemented related to integration of the Merger and consolidating operating facilities and headcount.
Results improved in all segments compared to the prior year period, as Rocky Mountains segment operating loss was $11.1, Southwest segment operating loss was $15.3, and Northeast/Mid-Con segment operating loss was $8.9 for the nine months ended October 31, 2021, in each case primarily driven by lower impairment and other charges as well as higher rig count and improved pricing.
Income tax expense. For the nine months ended October 31, 2021, income tax expense was $0.4, as compared to income tax expense of $0.3 in the prior year period, and was comprised primarily of state and local taxes. The Company did not recognize a tax benefit on its year-to-date losses because it has a valuation allowance against its deferred tax balances, which prevents the Company from recording such benefit.
Net loss. For the nine months ended October 31, 2021, net loss was $80.6, as compared to $301.8 in the prior year period, primarily due to a decrease in impairment and other charges from $213.1 in 2020 to $0.8 in 2021, along with above-mentioned increase in activity as well as improvements in pricing.
Liquidity and Capital Resources
We require capital to fund ongoing operations, including maintenance expenditures on our existing fleet and equipment, organic growth initiatives, investments and acquisitions. Our primary sources of liquidity to date have been capital contributions from our equity and note holders and borrowings under the Company’s senior secured credit agreement dated August 10, 2018 ("ABL Facility") and cash flows from operations. At October 31, 2021, we had $40.8 of cash and cash equivalents and total $40.0 available and net $30.0 available after $10.0 fixed charge coverage ratio ("FCCR") holdback on the October 31, 2021 ABL Facility Borrowing Base Certificate, which resulted in a total liquidity position of $80.8 and a net liquidity position of $70.8.
Our cash flow used in operations for the nine months ended October 31, 2021 was approximately $43.2 as compared to approximately $35.8 used in operations for the same period in 2020. In response to declining customer activity and commodity price instability, in the third quarter of 2020 we implemented actions to achieve our previously announced annualized run-rate cost synergies. By the end of first quarter of 2021, the
Company implemented approximately $46.0 of annualized cost savings and also identified and actioned an additional $4.4 of annualized cost savings. However, there is no certainty that cash flow will improve or that we will have positive operating cash flow for a sustained period of time. Our operating cash flow is sensitive to many variables, the most significant of which are utilization and profitability, the timing of billing and customer collections, payments to our vendors, repair and maintenance costs and personnel, any of which may affect our available cash. The COVID-19 pandemic and the related significant decrease in the price of oil resulted in a decrease in demand for our services in the last part of the first quarter through the third quarter of 2020. We started to see a moderate increase in overall activity throughout the first three quarters of 2021, which we expect to continue into the remainder of the fiscal year. Additionally, should our customers experience financial distress due to the current market conditions, they could default on their payments owed to us, which would affect our cash flows and liquidity. As of October 31, 2021, we have $5.0 of trade accounts receivable reserved for customers in bankruptcy, primarily related to Magellan. See Part II, Item 1 "Legal Proceedings" for more information regarding the amount due from Magellan.
Our primary use of capital resources has been for funding working capital and investing in property and equipment used to provide our services. We actively manage our capital spending and are focused on required maintenance spending. In addition, we regularly monitor potential sources of capital, including equity and debt financings, in an effort to meet our planned capital expenditure and liquidity requirements and reduce cost. The COVID-19 pandemic, coupled with the global crude oil supply and demand imbalance and the resulting volatility in U.S. onshore oil and gas activity, has significantly affected the value of our common stock, which, without a viable recovery and uptick in the demand for our services, may reduce our ability to access capital in the bank and capital markets, including through equity or debt offerings.
At October 31, 2021, we had $40.8 of cash and cash equivalents. Cash on hand at October 31, 2021 decreased by $6.3, as compared with $47.1 cash on hand at January 31, 2021 as a result of $43.2 of cash used in operating activities offset by $6.2 of cash provided by investing activities and $30.7 of cash provided by financing activities. Our liquidity requirements consist of working capital needs, debt service obligations and ongoing capital expenditure requirements. Our primary requirements for working capital are directly related to the activity level of our operations.
The following table sets forth our cash flows for the periods presented below:
Nine Months Ended
October 31, 2021
October 31, 2020
Net cash used in operating activities
$
(43.2)
$
(35.8)
Net cash provided by (used in) investing activities
6.2
(10.3)
Net cash provided by financing activities
30.7
2.4
Net change in cash
(6.3)
(43.7)
Cash balance end of period
$
40.8
$
79.8
Net cash used in operating activities
Net cash used in operating activities was $43.2 for the nine months ended October 31, 2021, as compared to $35.8 for the nine months ended October 31, 2020. The decrease in operating cash flows was primarily attributable to working capital investments associated with increased accounts receivable from associated increased revenue and utilization.
Net cash provided by (used in) investing activities
Net cash provided by investing activities was $6.2 for the nine months ended October 31, 2021, as compared to net cash used in investing activities of $10.3 for the nine months ended October 31, 2020. The increase in investing cash flows for the nine months ended October 31, 2021 was primarily driven by sales of facilities, trucks and other idle assets resulting from cost reduction initiatives, as well as lost-in-hole tools billed to customers as a result of increased activity.
Net cash provided by financing activities was $30.7 for the nine months ended October 31, 2021, compared to $2.4 for the nine months ended October 31, 2020. During the nine months ended October 31, 2021, borrowings under the ABL facility were $30.0 and proceeds from stock issuance, net of costs were $4.8, offset by $1.8 paid on financed payables, $2.0 paid on capital lease obligations, and $0.3 paid for treasury shares in connection with the settlement of income tax and related benefit withholding obligations arising from vesting of restricted stock grants under the Company’s long-term incentive program.
Financing Arrangements
We entered into a $100.0 ABL Facility on August 10, 2018. The ABL Facility became effective on September 14, 2018 and is scheduled to mature in September 2023. Borrowings under the ABL Facility bear interest at a rate equal to the London Interbank Offered Rate (“LIBOR”) (as defined in the ABL Facility) plus the applicable margin (as defined). Availability under the ABL Facility is tied to a borrowing base formula and the ABL Facility has no maintenance financial covenants as long as we maintain a minimum level of borrowing availability. The ABL Facility is secured by, among other things, a first priority lien on our accounts receivable and inventory and contains customary conditions precedent to borrowing and affirmative and negative covenants. There was $30.0 outstanding under the ABL Facility as of October 31, 2021. Total letters of credit outstanding under the ABL Facility were $5.0 at October 31, 2021. The effective interest rate under the ABL Facility was approximately 4.75% on October 31, 2021. Accrued interest as of October 31, 2021 was $0.3.
Financial Services industry and market participants continue to work towards transitioning away from interbank offered rates ("IBOR"), including the LIBOR, that are being phased out imminently. This phasing out will have an impact on the ABL Facility that utilizes LIBOR as a benchmark. To transition from IBOR Reference Rate, the ABL Facility agreement between the Company and JP Morgan Chase & Co. ("JP Morgan"), which currently has borrowings outstanding of $30.0, will be amended to adopt an alternate rate effective on or before June 30, 2023.Until the ABL Facility agreement is amended to allow for Secured Overnight Financing Rate ("SOFR") as the replacement to LIBOR, the Alternate Base Rate ("ABR"), is the default rate that JP Morgan has agreed to use as the LIBOR replacement. See Note 2 for further discussion of upcoming changes from LIBOR to Term SOFR.
The ABL Facility includes a springing financial covenant which requires the Company’s consolidated FCCR to be at least 1.0 to 1.0 if availability falls below the greater of $10.0 or 15% of the borrowing base. At all times during the nine months ended October 31, 2021, availability exceeded this threshold, and the Company was not subject to this financial covenant. As of October 31, 2021, the FCCR was below 1.0 to 1.0. The Company was in full compliance with its credit facility as of October 31, 2021.
In conjunction with the acquisition of Motley in 2018, we issued $250.0 principal amount of 11.5% senior secured notes due 2025 (the "Notes") offered pursuant to Rule 144A under the Securities Act of 1933 (as amended, the "Securities Act") and to certain non-U.S. persons outside the United States in compliance with Regulation S under the Securities Act. On a net basis, after taking into consideration the debt issuance costs for the Notes, total debt as of October 31, 2021 was $244.6. The Notes bear interest at an annual rate of 11.5%, payable semi-annually in arrears on May 1 and November 1. Accrued interest as of October 31, 2021 was $14.4.
Capital Requirements and Sources of Liquidity
Our capital expenditures were $7.5 during the nine months ended October 31, 2021, compared to $11.1 in the nine months ended October 31, 2020. We expect to incur a total between $9.0 to $11.0 in capital expenditures for the year ending December 31, 2021, based on current industry conditions. This is more than a 30% reduction from the previous range of $14.0 to $16.0, partially driven by the change in year-end. 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, the ABL Facility availability, Equity Distribution Agreement (defined below) and cash flow from operations. We have total funds available of $40.0 and net funds available of $30.0, after $10.0 FCCR holdback, as of October 31, 2021, from our $100.0 ABL Facility (under which the amount of availability depends in part on a borrowing base tied to the aggregate amount of our accounts receivable and inventory satisfying specified criteria and our compliance with a minimum fixed charge coverage ratio).
Our ability to satisfy our liquidity requirements depends on our future operating performance, which is affected by prevailing economic and political conditions, the level of drilling, completion, production and intervention services activity for North American onshore oil and natural gas resources, the continuation of the COVID-19 pandemic, and financial and business and other factors, many of which are beyond our control. We believe based on our current forecasts, our cash on hand, the ABL Facility availability, the Equity Distribution Agreement (defined below), together with our cash flows, will provide us with the ability to fund our operations, meet our debt service obligations, and make planned capital expenditures for at least the next 12 months. However, we can make no assurances regarding our ability to achieve our forecasts, which are materially dependent on our financial performance and demand for our services.
The Company also continues to assess various sources and options including public and private financings to bolster its liquidity and believes that, given current market conditions, it has opportunities to do so, however, there are no guarantees regarding these future financings.
Equity Distribution Agreement
On June 14, 2021, the Company entered into an Equity Distribution Agreement (the “Equity Distribution Agreement”) with Piper Sandler & Co. as sales agent (the “Agent”). Pursuant to the terms of the Equity Distribution Agreement, the Company may sell from time to time through the Agent (the “Offering”) the Company’s common stock, par value $0.01 per share, having an aggregate offering price of up to $50.0 (the “Common Stock”).
Any Common Stock offered and sold in the Offering will be issued pursuant to the Company’s shelf registration statement on Form S-3 (Registration No. 333-256149) filed with the SEC on May 14, 2021 and declared effective on June 11, 2021 (the “Registration Statement”), the prospectus supplement relating to the Offering filed with the SEC on June 14, 2021 and any applicable additional prospectus supplements related to the Offering that form a part of the Registration Statement. Sales of Common Stock under the Equity Distribution Agreement may be made in any transactions that are deemed to be “at the market offerings” as defined in Rule 415 under the Securities Act of 1933, as amended (the “Securities Act”).
The Equity Distribution Agreement contains customary representations, warranties and agreements by the Company, indemnification obligations of the Company and the Agent, including for liabilities under the Securities Act, other obligations of the parties and termination provisions. Under the terms of the Equity Distribution Agreement, the Company will pay the Agent a commission equal to 3% of the gross sales price of the Common Stock sold.
The Company plans to use the net proceeds from the Offering, after deducting the Agent’s commissions and the Company’s offering expenses, for general corporate purposes, which may include, among other things, paying or refinancing all or a portion of the Company’s then-outstanding indebtedness, and funding acquisitions, capital expenditures and working capital.
During the three and nine months ended October 31, 2021, the Company sold 1,070,000 and 1,130,216 shares of Common Stock, respectively, for gross proceeds of approximately $4.9 and $5.5, respectively, and paid legal and administrative fees of $0.1 and $0.7, respectively.
As a smaller reporting company, we are not required to provide the disclosure required by Item 303(a)(5)(i) of Regulation S-K.
Off-Balance Sheet Arrangements
Indemnities, Commitments and Guarantees
In the normal course of our business, we make certain indemnities, commitments and guarantees under which we may be required to make payments in relation to certain transactions. These indemnities include indemnities to various lessors in connection with facility leases for certain claims arising from such facility or lease and indemnities to other parties to certain acquisition agreements. The duration of these indemnities, commitments and guarantees varies and, in certain cases, is indefinite. Many of these indemnities, commitments and guarantees provide for limitations on the maximum potential future payments we could be obligated to make. However, we are unable to estimate the maximum amount of liability related to our indemnities, commitments and guarantees because such liabilities are contingent upon the occurrence of events that are not reasonably determinable. Our management believes that any liability for these indemnities, commitments and guarantees would not be material to our financial statements. Accordingly, no significant amounts have been accrued for indemnities, commitments and guarantees.
We have employment agreements with certain key members of management expiring on various dates. Our employment agreements generally provide for certain protections in the event of a change of control. These protections generally include the payment of severance and related benefits under certain circumstances in the event of a change in control.
Lease Commitments
The Company finances its use of certain facilities and equipment under committed lease arrangements provided by various institutions. Since the terms of these arrangements meet the accounting definition of operating lease arrangements, the aggregate sum of future minimum lease payments is not reflected on the consolidated balance sheets. At October 31, 2021, future minimum lease payments under these arrangements approximated $69.6 of which $30.1 is related to long-term real estate leases and $23.5 is related to long-term coiled tubing unit leases.
Critical Accounting Policies
Critical accounting policies are defined as those that are reflective of significant judgments and uncertainties, and potentially result in materially different results under different assumptions and conditions. We believe that our critical accounting policies are limited to those described in the Critical Accounting Policies section of Management’s Discussion and Analysis of Financial Condition and Results of Operations included in our 2020 Annual Report on Form 10-K filed with the SEC on April 28, 2021.
Recent Accounting Pronouncements
See Note 2 “Recent Accounting Pronouncements” to our condensed consolidated financial statements for a discussion of recently issued accounting pronouncements. As an “emerging growth company” under the Jumpstart Our Business Startups Act (the “JOBS Act”), we are offered an opportunity to use an extended transition period for the adoption of new or revised financial accounting standards. We operate under the reduced reporting requirements and exemptions, including the longer phase-in periods for the adoption of new or revised financial accounting standards, until we are no longer an emerging growth company. Our election to use the phase-in periods permitted by this election may make it difficult to compare our financial statements to those of non-emerging growth companies and other emerging growth companies that have opted out of the longer phase-in periods under Section 107 of the JOBS Act and who will comply with new or
revised financial accounting standards. If we were to subsequently elect instead to comply with these public company effective dates, such election would be irrevocable pursuant to Section 107 of the JOBS Act.
ITEM 3.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
As a smaller reporting company, we are not required to provide the information required by Item 305 of Regulation S-K.
ITEM 4.
CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
We have established disclosure controls and procedures that are designed to ensure that the information required to be disclosed by the Company in the reports that it files or submits under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), is recorded, processed, summarized and reported within the time periods specified in the Commission’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to provide reasonable assurance that information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act is accumulated and communicated to the Company’s management, including its principal executive and principal financial officers (who are our Chief Executive Officer and Chief Financial Officer, respectively), or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. In designing and evaluating our disclosure controls and procedures, management recognized that disclosure controls and procedures can provide only reasonable, not absolute, assurance that the objectives of the disclosure controls and procedures are met.
In connection with the preparation of this Quarterly Report for the quarter ended October 31, 2021, an evaluation was performed under the supervision of and with the participation of management, including the Chief Executive Officer and Chief Financial Officer, of the effectiveness of the Company’s disclosure controls and procedures. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that its disclosure controls and procedures were effective as of October 31, 2021.
Changes in Internal Control over Financial Reporting
There have been no changes in our internal control over financial reporting during the period covered by this Quarterly Report on Form 10-Q that have materially affected or, are reasonably likely to materially affect, our internal control over financial reporting.
PART II – OTHER INFORMATION
ITEM 1.
LEGAL PROCEEDINGS
The Company is at times either a plaintiff or a defendant in various legal actions arising in the normal course of business, the outcomes of which, in the opinion of management, neither individually nor in the aggregate are likely to result in a material adverse effect on the Company’s financial condition, cash flows and results of operations.
On March 9, 2021, the Company filed claims in the District Court of Harris County, Texas against Magellan E&P Holdings, Inc. ("Magellan"), Redmon-Keys Insurance Group, Inc. and certain underwriters at Lloyd's ("Underwriters") to recover $4.6 owed on invoices duly issued by the Company for services rendered on behalf of the defendants in response to an offshore well blowout near Bob Hall Pier in Corpus Christi, Texas. Magellan did not dispute the invoices but alleged an inability to pay prior to obtaining funding from Underwriters under Magellan's Owner's Extra Expense Policy. On March 19, 2021, Underwriters filed a declaratory judgment action in the United States District Court for the Southern District of Texas seeking a declaration that certain blowout related expenses fall outside of policy coverage. On March 30, 2021,
Magellan filed for bankruptcy pursuant to Chapter 7 of the U.S. bankruptcy code. The bankruptcy proceedings are ongoing. We expect that the trustee will continue to pursue claims against Underwriters as well as preference and other claims to maximize the value of the Chapter 7 estate for the benefit of trade creditors. During the year ended January 31, 2021, the Company reserved the full amount of its invoices totaling $4.6 as a prudent action in light of the Chapter 7 filing.
ITEM 1A.
RISK FACTORS
In addition to the information set forth in this report, you should carefully consider the risk factors previously described in Part I, Item IA. “Risk Factors” in our Annual Report on Form 10-K for the fiscal year ended January 31, 2021.
ITEM 2.
UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
Purchases of Equity Securities by the Issuer and Affiliated Purchasers
The following table presents the total number of shares of our common stock that we repurchased during the three months ended October 31, 2021:
Period
Total number of shares purchased(1)
Average price paid per share(2)
Total number of shares purchased as part of publicly announced plans or programs(3)
Approximate dollar value of shares that may yet be purchased under the plans or programs
August 1, 2021 - August 31, 2021
—
$
—
—
$
48,859,603
September 1, 2021 - September 30, 2021
—
$
—
—
$
48,859,603
October 1, 2021 - October 31, 2021
—
$
—
—
$
48,859,603
Total
—
—
(1) Includes shares purchased from employees in connection with the settlement of income tax and related benefit withholding obligations arising from vesting of restricted stock grants under the Company’s Long-Term Incentive Plan.
(2) The average price paid per share of common stock repurchased under the share repurchase program includes commissions paid to the brokers.
(3) In August 2019, our Board authorized a share repurchase program for the repurchase of outstanding shares of the Company’s common stock having an aggregate purchase price up to $50.
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
KLX ENERGY SERVICES HOLDINGS, INC.
By:
/s/ Christopher J. Baker
Christopher J. Baker
President and Chief Executive Officer
Date: December 10, 2021
By:
/s/ Keefer M. Lehner
Keefer M. Lehner
Executive Vice President and Chief Financial Officer
Date: December 10, 2021
By:
/s/ Geoffrey C. Stanford
Geoffrey C. Stanford
Senior Vice President and Chief Accounting Officer
