UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

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Form 10-Q

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(Registrant’s telephone number, including area code)

(Former name, former address and former fiscal year, if changed since last report)

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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  ý    No  ¨  

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted 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 and post such files).    Yes  ý    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.

PART I — FINANCIAL INFORMATION

(in thousands, except per share data)

(unaudited)

(in thousands)

(unaudited)

NOTES TO CONDENSED CONSOLIDATED UNAUDITED FINANCIAL STATEMENTS

NOTE 1. GENERAL

Key Energy Services, Inc., and its wholly owned subsidiaries (collectively, “Key,” the “Company,” “we,” “us,” “its,” and “our”) provide a full range of well services to major oil companies and independent oil and natural gas production companies. Our services include rig-based and coiled tubing-based well maintenance and workover services, well completion and recompletion services, fluid management services, fishing and rental services, and other ancillary oilfield services. Additionally, certain of our rigs are capable of specialty drilling applications. We operate in most major oil and natural gas producing regions of the continental United States. An important component of the Company’s growth strategy is to make acquisitions that will strengthen its core services or presence in selected markets, and the Company also makes strategic divestitures from time to time. The Company expects that the industry in which it operates will experience consolidation, and the Company expects to explore opportunities and engage in discussions regarding these opportunities, which could include mergers, consolidations or acquisitions or further dispositions or other transactions, although there can be no assurance that any such activities will be consummated.

The accompanying unaudited condensed consolidated financial statements were prepared using generally accepted accounting principles in the United States of America (“GAAP”) for interim financial information and in accordance with the rules and regulations of the Securities and Exchange Commission (the “SEC”). The condensed December 31, 2017 balance sheet was prepared from audited financial statements included in our Annual Report on Form 10-K for the year ended December 31, 2017 (the “2017 Form 10-K”). Certain information relating to our organization and footnote disclosures normally included in financial statements prepared in accordance with GAAP have been condensed or omitted in this Quarterly Report on Form 10-Q. These unaudited condensed consolidated financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto included in our 2017 Form 10-K.

The unaudited condensed consolidated financial statements contained in this report include all normal and recurring material adjustments that, in the opinion of management, are necessary for a fair presentation of our financial position, results of operations and cash flows for the interim periods presented herein. The results of operations for the threenine months ended March 31,September 30, 2018 are not necessarily indicative of the results expected for the full year or any other interim period, due to fluctuations in demand for our services, timing of maintenance and other expenditures, and other factors.

We have evaluated events occurring after the balance sheet date included in this Quarterly Report on Form 10-Q and through the date on which the unaudited condensed consolidated financial statements were issued, for possible disclosure of a subsequent event.

NOTE 2. SIGNIFICANT ACCOUNTING POLICIES AND ESTIMATES

The preparation of these unaudited condensed consolidated financial statements requires us to develop estimates and to make assumptions that affect our financial position, results of operations and cash flows. These estimates may also impact the nature and extent of our disclosure, if any, of our contingent liabilities. Among other things, we use estimates to (i) analyze assets for possible impairment, (ii) determine depreciable lives for our assets, (iii) assess future tax exposure and realization of deferred tax assets, (iv) determine amounts to accrue for contingencies, (v) value tangible and intangible assets, (vi) assess workers’ compensation, vehicular liability, self-insured risk accruals and other insurance reserves, (vii) provide allowances for our uncollectible accounts receivable, (viii) value our asset retirement obligations, and (ix) value our equity-based compensation. We review all significant estimates on a recurring basis and record the effect of any necessary adjustments prior to publication of our financial statements. Adjustments made with respect to the use of estimates relate to improved information not previously available. Because of the limitations inherent in this process, our actual results may differ materially from these estimates. We believe that the estimates used in the preparation of these interim financial statements are reasonable.

Revenue Recognition

We recognize revenue based on the ASC 606 model, comprising the following five steps: (i) a contract with the customer exists, (ii) performance obligations have been identified, (iii) the price to the customer has been determined, (iv) the price has been allocated to the performance obligations, and (v) the performance obligation is satisfied. We generally determine that these steps have been satisfied as follows:

A contract with the customer exists when a final understanding between us and our customer has occurred, and can be evidenced by a completed customer purchase order, field ticket, supplier contract, or master service agreement.

Performance obligations have been identified when we have determined the contractual requirements pursuant to the terms of the arrangement. We have a process to determine performance obligations for our contracts.

The price to the customer is determinable and allocated when the amount that is required to be paid is estimated. A price that is determinable is evidenced by contractual terms, our price book, a completed customer purchase order, or a field ticket.

The performance obligation is satisfied in a manner that best depicts the transfer of goods or services to the customer. The control over services is transferred as the services are rendered to the customer. Specifically, we recognize revenue as the services are provided, typically daily, as we have the right to invoice the customer for the services performed.

As an accounting policy election, the Company excludes from the measurement of the transaction price all taxes assessed by a governmental authority that are both imposed on and concurrent with a specific revenue-producing transaction and collected by the Company from a customer.

There have been no material changes or developments in our evaluation of accounting estimates and underlying assumptions or methodologies that we believe to be a “Critical Accounting Policy or Estimate” as disclosed in our 2017 Form 10-K.

ASU 2016-13. In June 2016, the FASB issued ASU 2016-13, Financial Instruments—Credit Losses (Topic 326), Measurement of Credit Losses on Financial Instruments that will change how companies measure credit losses for most financial assets and certain other instruments that aren’t measured at fair value through net income. The standard will replace today’s “incurred loss” approach with an “expected loss” model for instruments measured at amortized cost. For available-for-sale debt securities, entities will be required to record allowances rather than reduce the carrying amount. The amendments in this update will be effective for annual periods beginning after December 15, 2019 and interim periods within those annual periods. Early adoption is permitted for annual periods beginning after December 15, 2018. The Company is evaluating the effect of this standard on our consolidated financial statements.

On January 1, 2018, we adopted ASC 606 using the full retrospective method applied to those contracts that were not completed as of December 15, 2016. As noted in prior periods, we emerged from voluntary reorganization under Chapter 11 of the United States Bankruptcy Code on December 15, 2016 and therefore applied fresh-start accounting and adopted ASC 606 in effect at the fresh-start accounting date. As a result of electing to use the full retrospective adoption approach as described above, results for reporting periods beginning after December 15, 2016 are presented under ASC 606.

The adoption of ASC 606 did not have a material impact on our consolidated financial statements, and we did not record any adjustments to opening retained earnings as of December 15, 2016, because our services and rental contracts are principally charged on an hourly or daily rate basis and are primarily short-term in nature, typically less than 30 days.

Revenues are recognized when control of the promised goods or services is transferred to our customers, in an amount that reflects the consideration we expect to be entitled to in exchange for those goods or services. The following table presents our revenues disaggregated by revenue source (in thousands). Sales taxes are excluded from revenues.

We have disaggregated our revenues by our reportable segments including U.S. Rig Services, Fluid ManagementFishing & Rental Services, Coiled Tubing Services and Fishing & RentalFluid Management Services.

Our U.S. Rig Services include the completion of newly drilled wells, workover and recompletion of existing oil and natural gas wells, well maintenance, and the plugging and abandonment of wells at the end of their useful lives. We also provide specialty drilling services to oil and natural gas producers with certain of our larger rigs that are capable of providing conventional and horizontal drilling services. Our rigs encompass various sizes and capabilities, allowing us to service all types of oil and gas wells.

We recognize revenue within the U.S. Rig Services segment by measuring progress toward satisfying the performance obligation in a manner that best depicts the transfer of goods or services to the customer. The control over services is transferred as the services are rendered to the customer. Specifically, we recognize revenue as the services are provided, typically daily, as we have the right to invoice the customer for the services performed. U.S. Rig Services are billed and paid monthly. Payment terms for U.S. Rig Services are usually 30 days from invoice receipt.

We provide transportationoffer a full line of services and well-site storagerental equipment designed for use in providing drilling and workover services. Fishing services for various fluids utilizedinvolve recovering lost or stuck equipment in connection with drilling, completions, workoverthe wellbore utilizing a broad array of “fishing tools.” Our rental tool inventory consists of drill pipe, tubulars, handling tools (including our patented Hydra-Walk® pipe-handling units and maintenance activities. We also provide disposal services for fluids produced subsequent to well completion. These fluids are removed from the well site and transported for disposal in saltwater disposal wells owned by us or a third party.services), pressure-control equipment, pumps, power swivels, reversing units, foam air units.

We recognize revenue within the Fluid ManagementFishing and Rental Services segment by measuring progress toward satisfying the performance obligation in a manner that best depicts the transfer of goods or services to the customer. The control over services

Coiled Tubing Services involve the use of a continuous metal pipe spooled onto a large reel, which is then deployed into oil and natural gas wells to perform various applications, such as wellbore clean-outs, nitrogen jet lifts, through-tubing fishing, and formation stimulations utilizing acid and chemical treatments. Coiled tubing is also used for a number of horizontal well applications such as milling temporary isolation plugs that separate frac zones, and various other pre- and post-hydraulic fracturing well preparation services.

We recognize revenue within the Coiled Tubing Services segment by measuring progress toward satisfying the performance obligation in a manner that best depicts the transfer of goods or services to the customer. The control over services is transferred as the services are rendered to the customer. Specifically, we recognize revenue, typically daily, as the services are provided as we have the right to invoice the customer for the services performed. Coiled Tubing Services are billed and paid monthly. Payment terms for Coiled Tubing Services are usually 30 days from invoice receipt.

We offerprovide transportation and well-site storage services for various fluids utilized in connection with drilling, completions, workover and maintenance activities. We also provide disposal services for fluids produced subsequent to well completion. These fluids are removed from the well site and transported for disposal in saltwater disposal wells owned by us or a full line of services and rental equipment designed for use in providing drilling and workover services. Fishing services involve recovering lost or stuck equipment in the wellbore utilizing a broad array of “fishing tools.” Our rental tool inventory consists of drill pipe, tubulars, handling tools (including our patented Hydra-Walk® pipe-handling units and services), pressure-control equipment, pumps, power swivels, reversing units, foam air units.third party.

We recognize revenue within the Fishing and RentalFluid Management Services segment by measuring progress toward satisfying the performance obligation in a manner that best depicts the transfer of goods or services to the customer. The control over services is transferred as the services are rendered to the customer. Specifically, we recognize revenue as the services are provided, typically daily, as we have the right to invoice the customer for the services performed. Fishing and RentalFluid Management Services are billed and paid monthly. Payment terms for Fishing and RentalFluid Management Services are usually 30 days from invoice receipt.

Our former International segment includesincluded our former operations in Canada and Russia. Our services in Russia consisted of rig-based services such as the maintenance, workover, and recompletion of existing oil wells, completion of newly-drilled wells, and plugging and abandonment of wells at the end of their useful lives. We also had a technology development and control systems business based in Canada, which was focused on the development of hardware and software related to oilfield service equipment controls, data acquisition and digital information flow.

We recognized revenue within the International segment by measuring progress toward satisfying the performance obligation in a manner that best depicted the transfer of goods or services to the customer. The control over services was transferred as the services were rendered to the customer. Specifically, we recognized revenue as the services were provided, typically daily, as we had the right to invoice the customer for the services performed. Services within the international segment were billed and paid monthly. Payment terms for services within the International segment were usually 30 days from invoice receipt.

Our contracts with customers may include multiple performance obligations. For such arrangements, we allocate revenues to each performance obligation based on its relative standalone selling price. We generally determine standalone selling prices based on the prices charged to customers or using expected cost-plus margin. For combined products and services within a contract, we account for individual products and services separately if they are distinct- i.e. if a product or service is separately identifiable from other items in the contract and if a customer can benefit from it on its own or with other resources that are readily available to the customer. The consideration (including any discounts) is allocated between separate products and services within a contract based on the prices at which we separately sell our services. For items that are not sold separately, we estimate the standalone selling prices using the expected cost-plus margin approach.

Under our revenue contracts, we invoice customers once our performance obligations have been satisfied, at which point payment is unconditional. Accordingly, our revenue contracts do not give rise to contract assets or liabilities under ASC 606.

We generally expense sales commissions when incurred because the amortization period would have been one year or less. These costs are recorded within general and administrative expenses.

The majority of our services are short-term in nature with a contract term of one year or less. For those contracts, we have utilized the practical expedient in ASC 606-10-50-14 exempting the Company from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less.

Further, in many of our service contracts we have a right to consideration from a customer in an amount that corresponds directly with the value to the customer of the entity’s performance completed to date (for example, a service contract in which an entity bills a fixed amount for each hour of service provided). For those contracts, we have utilized the practical expedient in ASC 606-10-55-18 exempting the Company from disclosure of the entity to recognize revenue in the amount to which the Company has a right to invoice.

Accordingly, we do not disclose the value of unsatisfied performance obligations for (i) contracts with an original expected length of one year or less and (ii) contracts for which we recognize revenue at the amount to which we have the right to invoice for services performed.

As of March 31,September 30, 2018 and December 31, 2017, the components of our debt were as follows (in thousands):

The ABL Facility provides the ABL Borrowers with the ability to borrow up to an aggregate principal amount equal to the lesser of (i) the aggregate revolving commitments then in effect and (ii) the sum of (a) 85% of the value of eligible accounts receivable plus (b) 80% of the value of eligible unbilled accounts receivable, subject to a limit equal to the greater of (x) $35 million and (y) 25% of the commitments. The amount that may be borrowed under the ABL Facility is subject to increase or reduction based on certain segregated cash or reserves provided for by the ABL Facility. In addition, the percentages of accounts receivable and unbilled accounts receivable included in the calculation described above is subject to reduction to the extent of certain bad debt write-downs and other dilutive items provided in the ABL Facility.

Borrowings under the ABL Facility will bear interest, at the ABL Borrowers’ option, at a per annum rate equal to (i) LIBOR for 30, 60, 90, 180, or, with the consent of the ABL Lenders, 360 days, plus an applicable margin that varies from 2.5% to 4.5% depending on the Borrowers’ fixed charge coverage ratio at such time or (ii) a base rate equal to the sum of (a) the greatest of (x) the prime rate, (y) the federal funds rate, plus 0.50% or (z) 30-day LIBOR, plus 1.0% plus (b) an applicable margin that varies from 1.50% to 3.50% depending on the Borrowers’ fixed charge coverage ratio at such time. In addition, the ABL Facility provides for unused line fees of 1.00% to 1.25% per year, depending on utilization, letter of credit fees and certain other factors.

The ABL Facility may in the future be guaranteed by certain of the Company’s existing and future subsidiaries (the “ABL Guarantors,” and together with the ABL Borrowers, the “ABL Loan Parties”). To secure their obligations under the ABL Facility, each of the ABL Loan Parties has granted or will grant, as applicable, to the Administrative Agent a first-priority security interest for the benefit of the ABL Lenders in its present and future accounts receivable, inventory and related assets and proceeds of the foregoing (the “ABL Priority Collateral”). In addition, the obligations of the ABL Loan Parties under the ABL Facility are secured by second-priority liens on the Term Priority Collateral (as described below under “Term Loan Facility”).

The revolving loans under the ABL Facility may be voluntarily prepaid, in whole or in part, without premium or penalty, subject to breakage or similar costs.

The ABL Facility contains certain affirmative and negative covenants, including covenants that restrict the ability of the ABL Loan Parties to take certain actions including, among other things and subject to certain significant exceptions, the incurrence of debt, the granting of liens, the making of investments, entering into transactions with affiliates, the payment of dividends and

On December 15, 2016, the Company entered into the Term Loan Facility among the Company, as borrower, certain subsidiaries of the Company named as guarantors therein, the financial institutions party thereto from time to time as Lenders (collectively, the “Term Loan Lenders”) and Cortland Capital Market Services LLC and Cortland Products Corp., as agent for the Lenders. The Term Loan Facility had an initial outstanding principal amount of $250 million.

The Term Loan Facility will mature on December 15, 2021, although such maturity date may, at the Company’s request, be extended by one or more of the Term Loan Lenders pursuant to the terms of the Term Loan Facility. Borrowings under the Term Loan Facility will bear interest, at the Company’s option, at a per annum rate equal to (i) LIBOR for one, two, three, six, or, with the consent of the Term Loan Lenders, 12 months, plus 10.25% or (ii) a base rate equal to the sum of (a) the greatest of (x) the prime rate, (y) the Federal Funds rate, plus 0.50% and (z) 30-day LIBOR, plus 1.0% plus (b) 9.25%.

The Term Loan Facility is guaranteed by certain of the Company’s existing and future subsidiaries (the “Term Loan Guarantors,” and together with the Company, the “Term Loan Parties”). To secure their obligations under the Term Loan Facility, each of the Term Loan Parties has granted or will grant, as applicable, to the agent a first-priority security interest for the benefit of the Term Loan Lenders in substantially all of each Term Loan Party’s assets other than certain excluded assets and the ABL Priority Collateral (the “Term Priority Collateral”). In addition, the obligations of the Term Loan Parties under the Term Loan Facility are secured by second-priority liens on the ABL Priority Collateral (as described above under “ABL Facility”).

The 2017 Tax Act was enacted on December 22, 2017. It is comprehensive tax reform legislation that contains significant changes to corporate taxation. Provisions on the enacted law include a permanent reduction of the corporate income tax rate from 35% to 21%, imposing a mandatory one-time tax on un-repatriated accumulated earnings of foreign subsidiaries, a partial limitation on the deductibility of business interest expense, a limitation on net operating losses to 80% of taxable income each year, a shift of the U.S. taxation of multinational corporations from a tax on worldwide income to a partial territorial system (along with rules that create a new U.S. minimum tax on earnings of foreign subsidiaries), and other related provisions to maintain the U.S. tax base.

We recognized the income tax effects of the 2017 Tax Act in accordance with Staff Accounting Bulletin No. 118, which provides SEC staff guidance for the application of ASC Topic 740, Income Taxes. The guidance allows for a measurement period of up to one year after the enactment date to finalize the recording of the related tax impacts. We believe the provisional amounts recorded during the fourth quarter of 2017 continue to represent a reasonable estimate of the accounting implications of the 2017 Tax Act. We did not identify any items for which the income tax effects of the 2017 Tax Act could not be reasonably estimated as of March 31,September 30, 2018. However, tax laws and regulations are subject to interpretation and the outcomes of tax disputes are inherently uncertain, and therefore our assessments can involve a series of complex judgments about future events and rely heavily on estimates and assumptions.

We are subject to U.S. federal income tax as well as income taxes in multiple state and foreign jurisdictions. Our effective tax rates were 0.0% and 0.6% for the three months ended March 31,September 30, 2018 and 2017 were 6.8% and 0.3%, respectively, and 2.4% and 1.2% for the nine months ended September 30, 2018 and 2017, respectively. The variance between our effective rate and the U.S. statutory rate is due to the mix of pre-tax profit between the U.S. and international taxing jurisdictions with varying statutory rates, the impact of permanent differences, and other tax adjustments, such as valuation allowances against deferred tax assets, and tax expense or benefit recognized for uncertain tax positions.    

We continued recording income taxes using a year-to-date effective tax rate method for the three and nine months ended March 31,September 30, 2018 and 2017. The use of this method was based on our expectations that a small change in our estimated ordinary income could result in a large change in the estimated annual effective tax rate. We will re-evaluate our use of this method each quarter until such time as a return to the annualized effective tax rate method is deemed appropriate.

The Company assesses the realizability of its deferred tax assets each period by considering whether it is more likely than not that all or a portion of the deferred tax assets will not be realized. Due to the history of losses in recent years and the continued challenges affecting the oil and gas industry, management continues to believe it is more likely than not that we will not be able to realize our net deferred tax assets.  No release of our deferred tax asset valuation allowance was made during the three or nine months ended March 31,September 30, 2018.

As of March 31,September 30, 2018, we had $0.1 million of unrecognized tax benefits, net of federal tax benefit, which, if recognized, would impact our effective tax rate. We record interest and penalties related to unrecognized tax benefits as income tax expense. We have accrued a liability of less than $0.1 million for the payment of interest and penalties as of March 31,September 30, 2018. We believe that it is reasonably possible that all remaining unrecognized tax positions may be recognized in the next twelve months as a result of a lapse of statute of limitations and settlement of ongoing audits.

NOTE 10. COMMITMENTS AND CONTINGENCIES

Various suits and claims arising in the ordinary course of business are pending against us. We conduct business throughout the continental United States and may be subject to jury verdicts or arbitrations that result in outcomes in favor of the plaintiffs. We are also exposed to various claims abroad. We continually assess our contingent liabilities, including potential litigation liabilities, as well as the adequacy of our accruals and our need for the disclosure of these items, if any. We establish a provision for a contingent liability when it is probable that a liability has been incurred and the amount is reasonably estimable. We have $3.8$3.4 million of other liabilities related to litigation that is deemed probable and reasonably estimable as of March 31,September 30, 2018. We do not believe that the disposition of any of these matters will result in an additional loss materially in excess of amounts that have been recorded.

We maintain reserves for workers’ compensation and vehicle liability on our balance sheet based on our judgment and estimates using an actuarial method based on claims incurred. We estimate general liability claims on a case-by-case basis. We maintain insurance policies for workers’ compensation, vehicle liability and general liability claims. These insurance policies carry self-insured retention limits or deductibles on a per occurrence basis. The retention limits or deductibles are accounted for in our accrual process for all workers’ compensation, vehicular liability and general liability claims. The deductibles have a $5 million maximum per vehicular liability claim, and a $2 million maximum per general liability claim and a $1 million maximum per workers’ compensation claim. As of March 31,September 30, 2018 and December 31, 2017, we have recorded $54.2$51.9 million and $52.2 million, respectively, of self-insurance reserves related to workers’ compensation, vehicular liabilities and general liability claims. Partially offsetting these liabilities, we had $15.7$14.8 million and $15.1 million of insurance receivables as of March 31,September 30, 2018 and December 31, 2017, respectively. We believe that the liabilities we have recorded are appropriate based on the known facts and circumstances and do not expect further losses materially in excess of the amounts already accrued for existing claims.

For environmental reserve matters, including remediation efforts for current locations and those relating to previously disposed properties, we record liabilities when our remediation efforts are probable and the costs to conduct such remediation efforts can be reasonably estimated. As of March 31,each of September 30, 2018 and December 31, 2017, we have recorded $2.0 million for our environmental remediation liabilities. We believe that the liabilities we have recorded are appropriate based on the known facts and circumstances and do not expect further losses materially in excess of the amounts already accrued.

Basic loss per share is determined by dividing net loss attributable to Key by the weighted average number of common shares actually outstanding during the period. Diluted loss per common share is based on the increased number of shares that would be outstanding assuming conversion of potentially dilutive outstanding securities using the treasury stock and “as if converted” methods.

Restricted stock units (“RSUs”), stock options, and warrants are included in the computation of diluted earnings per share using the treasury stock method. Restricted stock awards are legally considered issued and outstanding when granted and are included in basic weighted average shares outstanding.

No events occurred after March 31,September 30, 2018 that would materially affect the number of weighted average shares outstanding.

Common Stock Awards

We recognized employee share-based compensation expense of $2.0$1.6 million and $2.8$2.5 million during the three months ended March 31,September 30, 2018 and 2017, respectively. We recognized employee share-based compensation expense of $4.0 million and $8.2 million during the nine months ended September 30, 2018 and 2017, respectively. Our employee share-based awards, including common stock awards, stock option awards and phantom shares, vest in equal installments over a three-year period. Additionally, we recognized share-based compensation expense related to our outside directors of $0.3$0.1 million during the three months ended March 31,September 30, 2018 and 2017. We recognized share-based compensation expense related to our outside directors of $0.6 million during the nine months ended September 30, 2018 and 2017. The unrecognized compensation cost related to our unvested share-based awards as of March 31,September 30, 2018 is estimated to be $11.5$8.3 million and is expected to be recognized over a weighted-average period of 1.71.5 years.

Stock Option Awards

We recognized compensation expense related to our stock options of less than $0.1 millionzero and $0.9$0.8 million during the three months ended March 31,September 30, 2018 and 2017, respectively. Our employee stock options vest in equal installments over a four-year period. The unrecognizedWe recognized compensation costexpense related to our unvested stock options as of March 31,zero and $2.7 million during the nine months ended September 30, 2018 is estimatedand 2017, respectively. As of September 30, 2018, all outstanding stock options are vested and there are no unrecognized costs related to be less than $0.1 million and is expected to be recognized over a weighted-average period of 1.7 years.our stock options.

Phantom Share Plan

We recognized compensation expense related to our phantom shares of $0.3less than $0.1 million and zero during the three months ended March 31,September 30, 2018 and 2017, respectively. OurWe recognized compensation expense related to our phantom shares vest ratably over a three-year period.of $0.8 million and zero during the nine months ended September 30, 2018 and 2017, respectively. The unrecognized compensation cost related to our unvested phantom shares as of March 31,September 30, 2018 is estimated to be $1.9$0.9 million and is expected to be recognized over a weighted-average period of 1.81.3 years.

NOTE 13. TRANSACTIONS WITH RELATED PARTIES

The Company has purchased or sold equipment andor services from a few affiliates of certain directors. Additionally, the Company has a corporate advisory services agreement between with Platinum Equity Advisors, LLC (“Platinum”) pursuant to which Platinum provides certain business advisory services to the Company. The dollar amounts related to these related party activities are not material to the Company’s condensed consolidated financial statements.

NOTE 15. SEGMENT INFORMATION

Our reportable business segments are U.S. Rig Services, Fluid Management Services, Coiled Tubing Services, Fishing and Rental Services, Coiled Tubing Services, Fluid Management Services and, in 2017, International. We also have a “Functional Support” segment associated with overhead and other costs in support of our reportable segments. Our U.S. Rig Services, Fluid ManagementFishing and Rental Services, Coiled Tubing Services Fishing and RentalFluid Management Services operate geographically within the United States. The International reportable segment includes our former operations in Canada and Russia. We completed the sale of our Canadian subsidiary and Russian subsidiary in the second and third quarters of 2017, respectively. We evaluate the performance of our segments based on gross margin measures. All inter-segment sales pricing is based on current market conditions.

Our U.S. Rig Services include the completion of newly drilled wells, workover and recompletion of existing oil and natural gas wells, well maintenance, and the plugging and abandonment of wells at the end of their useful lives. We also provide specialty drilling services to oil and natural gas producers with certain of our larger rigs that are capable of providing conventional and horizontal drilling services. Our rigs encompass various sizes and capabilities, allowing us to service all types of wells. Many of our rigs are outfitted with our proprietary KeyView® technology, which captures and reports well site operating data and provides safety control systems. We believe that this technology allows our customers and our crews to better monitor well site operations, improves efficiency and safety, and adds value to the services that we offer.

The completion and recompletion services provided by our rigs prepare wells for production, whether newly drilled, or recently extended through a workover operation. The completion process may involve selectively perforating the well casing to access production zones, stimulating and testing these zones, and installing tubular and downhole equipment. We typically provide a well service rig and may also provide other equipment to assist in the completion process. Completion services vary by well and our work may take a few days to several weeks to perform, depending on the nature of the completion.

The workover services that we provide are designed to enhance the production of existing wells and generally are more complex and time consuming than normal maintenance services. Workover services can include deepening or extending wellbores into new formations by drilling horizontal or lateral wellbores, sealing off depleted production zones and accessing previously bypassed production zones, converting former production wells into injection wells for enhanced recovery operations and conducting major subsurface repairs due to equipment failures. Workover services may last from a few days to several weeks, depending on the complexity of the workover.

Maintenance services provided with our rig fleet are generally required throughout the life cycle of an oil or natural gas well. Examples of these maintenance services include routine mechanical repairs to the pumps, tubing and other equipment, removing debris and formation material from wellbores, and pulling rods and other downhole equipment from wellbores to identify and resolve production problems. Maintenance services are generally less complicated than completion and workover related services and require less time to perform.

Our rig fleet is also used in the process of permanently shutting-in oil or natural gas wells that are at the end of their productive lives. These plugging and abandonment services generally require auxiliary equipment in addition to a well servicing rig. The demand for plugging and abandonment services is not significantly impacted by the demand for oil and natural gas because well operators are required by state regulations to plug wells that are no longer productive.

We provide transportation and well-site storage services for various fluids utilized in connection with drilling, completions, workover and maintenance activities. We also provide disposal services for fluids produced subsequent to well completion. These fluids are removed from the well site and transported for disposal in saltwater disposal wells owned by us or a third party. In addition, we operate a fleet of hot oilers capable of pumping heated fluids used to clear soluble restrictions in a wellbore. Demand and pricing for these services generally correspond to demand for our well service rigs.

Our former International segment includesincluded our former operations in Russia and Canada. In April 2015, we announced our decision to exit markets in which we participate outside of North America. To this end, we completed the sale of our Canadian subsidiary and Russian subsidiary in the second and third quarters of 2017, respectively. Our services in Russia consisted of rig-based services such as the maintenance, workover, and recompletion of existing oil wells, completion of newly-drilled wells, and plugging and abandonment of wells at the end of their useful lives. Our services in Canada consisted of technology development and control systems, which was focused on the development of hardware and software related to oilfield service equipment controls, data acquisition and digital information flow.

Our Functional Support segment includes unallocated overhead costs associated with administrative support for our U.S. and International reporting segments.

The following tables set forth our unaudited segment information as of and for the three and nine months ended March 31,September 30, 2018 and 2017 (in thousands):

Key Energy Services, Inc., and its wholly owned subsidiaries provide a full range of well services to major oil companies and independent oil and natural gas production companies. Our services include rig-based and coiled tubing-based well maintenance and workover services, well completion and recompletion services, fluid management services, fishing and rental services, and

PERFORMANCE MEASURES

The Baker Hughes U.S. rig count data, which is publicly available on a weekly basis, is often used as an indicator of overall Exploration and Production (“E&P”) company spending and broader oilfield activity. In assessing overall activity in the U.S. onshore oilfield service industry in which we operate, we believe that the Baker Hughes U.S. land drilling rig count is the best available barometer of E&P companies’ capital spending and resulting activity levels. Historically, our activity levels have been highly correlated with U.S. onshore capital spending by our E&P company customers as a group.

Internally, we measure activity levels for our well servicing operations primarily through our rig and trucking hours. Generally, as capital spending by E&P companies increases, demand for our services also rises, resulting in increased rig and trucking services and more hours worked. Conversely, when activity levels decline due to lower spending by E&P companies, we generally provide fewer rig and trucking services, which results in fewer hours worked.

DuringOver the first quarternine months of 2018, we experiencedstrengthening oil prices led to improvement in demand for our services, particularly those driven by the completion of oil and natural gas wells, and we were able to increase prices for most of our service offerings. While the oil price has increased to levels not experienced since the end of 2014 and we have seen improvement in demand across all of our service offerings, we have not yet seen a substantial change in activity as it relates to our customer’s spending for the maintenance of existing oil and gas wells, particularly conventional wells, along with the improvement in oil prices.wells. We believe that with a continued stabilization of oil prices at a level consistent with current pricing will over time, result in theincreases in demand for our services in future periods.

During the third quarter of 2018, we experienced a decline in our completion driven revenues, primarily in our coiled tubing services, due to increasea reduction in completion activities that we believe occurred as a result of the lack of take away pipeline capacity for operators in the Permian Basin. We expect that as take away capacity is added to the Permian Basin over 2019 demand for completion driven services will increase. Additionally, we believe that continued aging of horizontal wells and customers choosing to increase production through accretive regular well maintenance in these horizontal wells will strengthen demand and pricing for and increase the price of our well maintenance services over the next several years. With increased demand for oilfield services broadly and specifically in the services we offer, however, the demand for qualified employees will also increase, whichincrease. This may impact our ability to meet the needs of our customers and constrain our growth or offset price increases realized due to inflation in labor costs.costs necessary to attract and retain employees.

Revenues

Direct Operating Expenses

Our direct operating expenses increased $10.9$19.0 million, to $98.2$106.1 million (78.4%(78.8% of revenues), for the three months ended March 31,September 30, 2018, compared to $87.3$87.1 million (86.1%(78.7% of revenues) for the three months ended March 31,September 30, 2017. This increase is primarily a result of an increase in employee compensation costs, fuel expense and repair and maintenance expense due to an increase in activity levels and the increase in repair and maintenance expense due to costs associated with making idle equipment ready for work.expense.

Depreciation and Amortization Expense

Depreciation and amortization expense decreased $0.9increased $0.7 million, or 4.4%3.3%, to $20.4$21.8 million during the three months ended March 31,September 30, 2018, compared to $21.3$21.1 million for the three months ended March 31,September 30, 2017. This decreaseincrease is primarily due to depreciation expense related to equipment acquired in the sale businesses in our International segment and our frac stack equipment and well testing services business.last year.

General and Administrative Expenses

General and administrative expenses decreased $6.4$13.2 million, to $24.6$23.9 million (19.6%(17.8% of revenues), for the three months ended March 31,September 30, 2018, compared to $31.0$37.2 million (30.6%(33.6% of revenues) for the three months ended March 31,September 30, 2017. The decrease is primarily due to lower employee compensation costs due to reduced staffing levels.

Interest Expense, Net of Amounts Capitalized

Interest expense increased $0.4$0.6 million, or 5.6%7.6%, to $8.1$8.7 million for the three months ended March 31,September 30, 2018, compared to $7.7$8.1 million for the same period in 2017. TheThis increase is primarily related to the increase in the variable interest rate on our long-term debt.

During the three monthsquarter ended March 31,September 30, 2018, we recognized other income, net, of $1.0$0.2 million, compared to other income, net, of $0.2$4.6 million for the three monthsquarter ended March 31,September 30, 2017. Other income, net for the quarter ended September 30, 2017 includes a $4.7 million gain on sale related to our Russian subsidiary which was disposed of in the third quarter of 2017.

The following table summarizes the components of other income, net for the periods indicated (in thousands):indicated: