UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

 _____________________________________________

Form 10-Q

 _____________________________________________ 

(Registrant’s telephone number, including area code)

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

  ____________________________________________

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  ¨   

PART I — FINANCIAL INFORMATION

See the accompanying notes which are an integral part of these condensed consolidated financial statements.

(in thousands, except per share data)

(unaudited)

See the accompanying notes which are an integral part of these condensed consolidated financial statements.

(in thousands)

(unaudited)

See the accompanying notes which are an integral part of these condensed consolidated financial statements.

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 foreign national 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 StatesStates. 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 we have operationsthe Company also makes strategic divestitures from time to time. The Company expects that the industry in Russia, which we are attemptingit operates will experience consolidation, and the Company expects to sell. In addition, we have a technology developmentexplore opportunities and control systems business basedengage in Canada.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, 20162017 balance sheet was prepared from audited financial statements included in our Annual Report on Form 10-K for the year ended December 31, 20162017 (the “2016“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 20162017 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 three months ended March 31, 20172018 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.

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 20162017 Form 10-K.

Recent Accounting Developments

amount, timing, and uncertainty of revenue from contracts with customers. The core principle is to recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU 2014-09 must be adopted using either a full retrospective method or a modified retrospective method. DuringWe adopted the new standard effective January 1, 2018 using the full retrospective method and the adoption of this standard did not have a July 2015 meeting,material impact on our consolidated financial statements.

On January 1, 2018, we adopted ASC 606 using the FASB affirmed a proposalfull retrospective method applied to defer the effective datethose 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 new revenue standard for all entities by one year.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 ASU 2014-09 is effectiveof electing to use the full retrospective adoption approach as described above, results for the Company for interim and annual reporting periods beginning after December 15, 2017 with early2016 are presented under ASC 606.

The adoption permitted for interim and annual reporting periods beginning after December 15, 2016. We are currently evaluating the standard to determine theof ASC 606 did not have a material impact of its adoption on theour consolidated financial statements, however, management believesand 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.

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 financial statements will not be material.

The components of our other intangible assets as of March 31, 20172018 and December 31, 20162017 are as follows (in thousands):

Amortization expense for our intangible assets was less than $0.1 million and $0.5 million for the three months ended March 31, 20172018 and 2016, respectively.2017.

As of March 31, 20172018 and December 31, 2016,2017, 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 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.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

the sale of assets. The ABL Facility also contains a requirement that the ABL Borrowers comply, during certain periods, with a fixed charge coverage ratio of 1.00 to 1.00.

Term Loan Facility

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”).

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 0.6%0.0% and 0.3%0.6% for the three months ended March 31, 20172018 and 2016,2017, 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, including goodwill impairment expense, and other tax adjustments, such as valuation allowances against deferred tax assets, and tax expense or benefit recognized for uncertain tax positions.    

We have historically calculated the provision forcontinued recording income taxes during interim reporting periods by applying an estimate of the annual effective tax rate for the full fiscal year to year-to-date ordinary income or loss. Management believes the use of the annual effective tax rate method to be appropriate for prior interim reporting periods. However, we adoptedusing a year-to-date effective tax rate method for recording income taxes for the three-month periodthree months ended March 31, 2018 and 2017. The adoptionuse of this method was based on our expectations at March 31, 2017 that a small change in our estimated annual 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.

As of March 31, 2017,2018, we had $0.3$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, 2017.2018. We believe that it is reasonably possible that $0.2 million of our currentlyall 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 $5.2$3.8 million of other liabilities related to litigation that is deemed probable and reasonably estimable as of March 31, 2017.2018. 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.

In November 2015, the Santa Barbara County District Attorney filed a criminal complaint against two former employees and Key, specifically alleging three counts of violations of California Labor Code section 6425(a) against Key. The complaint sought unspecified penalties against Key related to an October 12, 2013 accident which resulted in the death of one Key employee at a drilling site near Santa Maria, California. An arraignment was held on February 10, 2016, where Key and its former employees pleaded not guilty to all charges.

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. As of March 31, 20172018 and December 31, 2016,2017, we have recorded $57.6$54.2 million and $58.7$52.2 million, respectively, of self-insurance reserves related to workers’ compensation, vehicular liabilities and general liability claims. Partially offsetting these liabilities, we had $16.6$15.7 million and $16.3$15.1 million of insurance receivables as of March 31, 20172018 and December 31, 2016,2017, 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, 20172018 and December 31, 2016,2017, we have recorded $3.3$2.0 million and $3.4 million, respectively, 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.

StockRestricted stock units (“RSUs”), stock options, stock appreciation rights (“SARs”) 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, 20172018 that would materially affect the number of weighted average shares outstanding.

We recognized employee share-based compensation expense of $2.8$2.0 million and $2.4$2.8 million during the three months ended March 31, 2018 and 2017, and 2016, respectively. Our employee share-based awards vest in equal installments over a three-year period. Additionally, we recognized share-based compensation expense related to our outside directors of $0.3 million and zero during the three months ended March 31, 20172018 and 2016, respectively. Our employee share-based awards vest in equal installments over a four-year period.2017. The unrecognized compensation cost related to our unvested share-based awards as of March 31, 20172018 is estimated to be $19.2$11.5 million and is expected to be recognized over a weighted-average period of 2.21.7 years.

We recognized compensation expense related to our stock options of $0.9less than $0.1 million and zero$0.9 million during the three months ended March 31, 20172018 and 2016,2017, respectively. Our employee stock options vest in equal installments over a four-year period. The unrecognized compensation cost related to our unvested stock options as of March 31, 20172018 is estimated to be $6.4less than $0.1 million and is expected to be recognized over a weighted-average period of 2.21.7 years.

We recognized compensation expense related to our phantom shares of $0.3 million and zero during the three months ended March 31, 2018 and 2017, respectively. Our phantom shares vest ratably over a three-year period. The unrecognized compensation cost related to our unvested phantom shares as of March 31, 2018 is estimated to be $1.9 million and is expected to be recognized over a weighted-average period of 1.8 years.

NOTE 13. TRANSACTIONS WITH RELATED PARTIES

NOTE 15. SEGMENT INFORMATION

Our reportable business segments are U.S. Rig Services, Fluid Management Services, Coiled Tubing Services, Fishing and Rental Services and 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 Management Services, Coiled Tubing Services, Fishing and Rental Services operate geographically within the United States. The International reportable segment includes our current and former operations in MexicoCanada and Russia. Our Canadian subsidiary is also reflected in our International reportable segment. During the fourth quarter of 2016, weWe completed the sale of our businessCanadian subsidiary and Russian subsidiary in Mexicothe second and we are currently in discussions to sell our business in Russia.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.

U.S. Rig 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 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.

Fluid Management Services

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.

Coiled Tubing 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.

Fishing and Rental Services

Demand for our fishing and rental services is closely related to capital spending by oil and natural gas producers, which is generally a function of oil and natural gas prices.

International

Our International segment includes 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. During the fourth quarter of 2016,To this end, we completed the sale of our businessCanadian subsidiary and Russian subsidiary in Mexicothe second and we are currentlythird quarters of 2017, respectively. Our services in discussions to sell our business in Russia. We providedRussia consisted of rig-based services such as the maintenance, workover, and recompletion of existing oil wells, completion of newly-

Functional Support

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

Financial Summary

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, foreign national 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,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. To that end, we have operationscompleted the sale of our Canadian subsidiary and Russian subsidiary in Russia,the second and third quarters of 2017, respectively. The Company expects that the industry in which we are attemptingit operates will experience consolidation, and the Company expects to sell. In addition, we have a technology developmentexplore opportunities and control systems business basedengage in Canada.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.

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 towith 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 lowerfewer hours worked.

sought to anticipate activity declines and have reshapedreduce our organizational and cost structure to mitigate the negative impact of these declines, we have continued to experience negative operating results and cash flows from operations. AlthoughIn 2017, oil prices have improvedrecovered off the low pointlows of 2016 withand spurred an increase in the November 2016 decisionBaker Hughes U.S. rig count and related well completion activity, however, the same magnitude of activity increase did not occur in our principal Rig Services business, as measured by OPECthe AESC well service rig count, as oil and gas producers’ production maintenance spending has not recovered to curtail the cartel’s oil production,same extent as new well drilling and our revenues improved throughcompletion spending.

During the first quarter of 2017,2018, we experienced improvement in demand for our services, particularly those driven by the completion of oil and natural gas wells, and 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, we have not experienced an increaseyet seen a substantial change in activity levels commensurateas it relates to our customer’s spending for the maintenance of existing oil and gas wells, particularly conventional wells, along with in the increaseimprovement in oil prices or the Baker Hughes U.S. land drilling rig count.prices. We believe that stability inwith a stabilization of oil prices at an attractive pricea level consistent with current pricing will, over time, result in the demand for our services to our customers coupled withincrease Additionally, we believe that continued aging of horizontal wells and customers choosing to increase production thoughthrough accretive regular well maintenance in these horizontal wells will allow forstrengthen demand for our services to continue to improve from the first quarter of 2017. We believe that an improvement in demand for our services will allow for increases in both activity and increase the price of our services over 2017.the next several years. With increased demand for oilfield services broadly, however, the demand for qualified employees will also increase, which may impact our ability to meet the needs of our customers or offset price increases realized due to offset inflation in labor costs with price increases from our customers.costs.

Revenues

Direct Operating Expenses

Our direct operating expenses decreased $3.3increased $10.9 million, to $87.3$98.2 million (86.1%(78.4% of revenues), for the three months ended March 31, 2017,2018, compared to $90.6$87.3 million (81.6%(86.1% of revenues) for the three months ended March 31, 2016. The decrease2017. This increase is primarily related to a decreaseresult 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 expense as we sought to reduce our cost structure and as a result of lower activity levels.ready for work.

Depreciation and Amortization Expense

Depreciation and amortization expense decreased $14.5$0.9 million, or 40.4%4.4%, to $21.3$20.4 million during the three months ended March 31, 2017,2018, compared to $35.8$21.3 million for the three months ended March 31, 2016. The2017. This decrease is primarily attributable to the reduction of property, plant and equipment due to the implementation of fresh start accountingsale businesses in the fourth quarter of 2016.our International segment and our frac stack equipment and well testing services business.

General and Administrative Expenses

General and administrative expenses decreased $15.2$6.4 million, to $31.0$24.6 million (30.6%(19.6% of revenues), for the three months ended March 31, 2017,2018, compared to $46.2$31.0 million (41.6%(30.6% of revenues) for the three months ended March 31, 2016.2017. The decrease is primarily due to lower employee compensation costs due to reduced staffing levels and reduction in wages and the $5.0 million FCPA settlement accrual and $2.4 million decrease in expenses related to the FCPA investigation, which was completed in 2016, partially offset by $1.8 million in professional fees related to restructuring in 2017.

Impairment Expense

We recorded a $0.2 million impairment duringDuring the three months ended March 31, 2018, we did not record an impairment. During the three months ended March 31, 2017, we recorded a $0.2 million impairment to reduce the carrying value of the assets and related liabilities of our Russian business unit, which is being held for sale,was sold in the third quarter of 2017, to fair market value. We recorded no impairment expense during the three months ended March 31, 2016.

Interest Expense, Net of Amounts Capitalized

Interest expense decreased $13.9increased $0.4 million, or 64.3%5.6%, to $7.7$8.1 million for the three months ended March 31, 2017,2018, compared to $21.6$7.7 million for the same period in 2016.2017. The decreaseincrease is primarily related to the elimination ofincrease in the Predecessor Company’s senior secured notes in connection withvariable interest rate on our emergence from voluntary reorganization.long-term debt.

During the three months ended March 31, 2017,2018, we recognized other income, net, of $0.2$1.0 million, compared to other income, net, of $1.2$0.2 million for the three months ended March 31, 2016. Our foreign exchange gain relates to U.S. dollar-denominated transactions in our foreign locations and fluctuations in exchange rates between local currencies and the U.S. dollar.2017.

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