Aly Energy Services, Inc. - Quarter Report: 2018 September (Form 10-Q)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D. C. 20549

Form 10-Q

x Quarterly Report Pursuant to Section 13 or 15 (d) of the Securities Exchange Act of 1934

For the Period Ended September 30, 2018

or

¨ Transition Report Pursuant to Section 13 or 15 (d) of the Securities Exchange Act of 1934

For the Transition Period From _____________to _____________

Commission File Number 033-92894

(713) 333-4000

(Registrant’s Telephone Number, including area code.)

Securities registered pursuant to Section 12(b) of the Act:

Securities registered pursuant to Section 12(g) of the Act: None

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 x 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 x No ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, 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.

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 x

At November 13, 2018, the registrant had 940,918 shares of common stock, $0.001 par value, outstanding.

Documents Incorporated by Reference: None

ALY ENERGY SERVICES, INC.

(A Delaware Corporation)

INDEX

PART I – FINANCIAL INFORMATION

Item 1. Unaudited Condensed Consolidated Financial Statements

The accompanying notes are an integral part of these condensed consolidated financial statements.

The accompanying notes are an integral part of these condensed consolidated financial statements.

The accompanying notes are an integral part of these condensed consolidated financial statements.

The accompanying notes are an integral part of these condensed consolidated financial statements.

NOTE 1 — NATURE OF OPERATIONS AND BASIS OF PRESENTATION

Nature of Operations

Aly Energy Services, Inc., together with its subsidiaries (“Aly Energy” or the “Company”), is a provider of oilfield services to leading oil and gas exploration and production (“E&P”) companies operating in unconventional plays in the United States (“U.S.”). Generally, the services we offer fall within two broad categories: surface rental and solids control. Our surface rental equipment includes a wide variety of large capacity tanks with circulating systems, associated pumps, separators, gas busters, mud mix plants and ancillary equipment. We also provide environmental containment berms to safeguard against spills from mud systems on the drilling rig site. Our solids control equipment includes large centrifuges, shakers, cuttings dryers and ancillary components that can be integrated into a closed loop mud system. We operate in the U.S., primarily in Texas, Oklahoma, and New Mexico.

Throughout this report, we refer to Aly Energy and its subsidiaries as “we”, “our” or “us”.

Basis of Presentation

Aly Energy has two wholly-owned subsidiaries with continuing operations: Aly Operating, Inc. and Aly Centrifuge Inc. Aly Operating, Inc. has one wholly-owned subsidiary: Austin Chalk Petroleum Services Corp. We operate as one business segment which services customers within the U.S.

The condensed consolidated financial statements have been prepared in conformity with accounting principles generally accepted in the United States of America (“U.S. GAAP”) and include the accounts of Aly Energy and each of its subsidiaries in the condensed consolidated balance sheets as of September 30, 2018 and December 31, 2017, in the condensed consolidated statements of operations for the three and nine months ended September 30, 2018 and 2017, and in the condensed consolidated statements of cash flows for the nine months ended September 30, 2018 and 2017. All significant intercompany transactions and account balances have been eliminated upon consolidation.

Reverse Stock Split

On August 7, 2018, the Company effected a 1-for-20 reverse stock split of its common stock (“Reverse Split”), as approved by its Board of Directors and stockholders. All information in this Quarterly Report on Form 10-Q relating to the number of common shares, price per share and per share amounts, including such information related to options and the conversion feature of the Series A convertible preferred stock, have been retroactively restated to give effect to the Reverse Split. See Note 5 – Stockholders’ Equity for further detail.

Interim Financial Information

The condensed consolidated balance sheet as of December 31, 2017 has been derived from our audited financial statements and the unaudited condensed consolidated financial statements of the Company are prepared in conformity with U.S. GAAP for interim financial reporting. Certain information and footnote disclosures normally included in annual financial statements prepared in accordance with U.S. GAAP have been condensed or omitted pursuant to the rules and regulations of the Securities and Exchange Commission. Therefore, these condensed consolidated financial statements should be read along with the annual audited consolidated financial statements and notes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2017. In management’s opinion, all adjustments necessary for a fair statement are reflected in the interim periods presented. Interim results for the three and nine months ended September 30, 2018 may not be indicative of results that will be realized for the full year ending December 31, 2018.

Recapitalization

In September 2016, certain of the Company’s principal stockholders formed Permian Pelican, Inc. (“Pelican”), formerly Permian Pelican, LLC, with the objective of consummating a recapitalization transaction (the “Recapitalization”) whereby (i) our obligations under our then existing credit facility and various capital leases would be restructured and, (ii) the Company’s then outstanding redeemable preferred stock (Aly Operating redeemable preferred stock and Aly Centrifuge redeemable preferred stock), subordinated note payable and contingent payment liability would be exchanged into common stock. The Recapitalization, completed on January 31, 2017, had a significant impact on our capital structure and on our consolidated financial statements for the years ended December 31, 2017 and 2016. Please see our Annual Report on Form 10-K for the year ended December 31, 2017 for a complete description of the Recapitalization and the impact on our consolidated financial statements.

Use of Estimates

The preparation of condensed consolidated financial statements in conformity with U.S. GAAP requires management to make certain estimates and assumptions. These estimates and assumptions affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the balance sheet date and the amounts of revenue and expenses recognized during the reporting period. Areas where critical accounting estimates are made by management include:

The Company analyzes its estimates based on historical experience and various other indicative assumptions that it believes to be reasonable under the circumstances. Under different assumptions or conditions, the actual results could differ, possibly materially, from those previously estimated. Many of the conditions impacting these assumptions are outside of the Company’s control.

Reclassifications

Certain reclassifications have been made to prior period condensed consolidated financial statements to conform to the current period presentations. These reclassifications had no effect on our consolidated financial position, results of operations or cash flows.

NOTE 2 — LONG-LIVED ASSETS

Property and Equipment

Major classifications of property and equipment are as follows (in thousands):

Depreciation and amortization expense related to property and equipment for the three months ended September 30, 2018 and 2017 was $0.7 million. Depreciation and amortization expense related to property and equipment for the nine months ended September 30, 2018 and 2017 was $2.1 million and $2.2 million, respectively.

Intangible Assets

Intangible assets consist of the following (in thousands):

Total amortization expense for the three months ended September 30, 2018 and 2017 was approximately $0.2 million. Total amortization expense for the nine months ended September 30, 2018 and 2017 was approximately $0.6 million.

NOTE 3 — LONG-TERM DEBT – RELATED PARTY

Long-term debt – related party consists of the following (in thousands):

As of December 31, 2017, subsequent to multiple amendments, the Company’s credit facility with Pelican (“Related Party Credit Facility”) consisted of a term loan, a revolving credit facility and a delayed draw term loan. The obligations under the credit facility are guaranteed by all of our subsidiaries and secured by substantially all of our assets. The credit facility contains customary events of default and covenants including restrictions on our ability to incur additional indebtedness, pay dividends or make other distributions, grant liens and sell assets. Borrowings under the credit facility are subject to monthly interest payments at an annual base rate of the six-month LIBOR rate on the last day of the calendar month plus a margin of 3.0%. The credit facility does not include any financial covenants. We were in full compliance with the credit facility as of September 30, 2018.

On June 30, 2018, the Company entered into the Third Amended and Restated Credit Agreement which, among other things, (i) combined the outstanding balances on the delayed draw term loan and the term loan and initiated a required monthly principal payment of approximately $83,000 on the aggregate outstanding balance of the term loan, (ii) expanded availability on the revolving credit facility by $0.7 million while simultaneously reducing the aggregate availability under the other lines of the facility by the same amount, and (iii) extended the maturity date of the facility to June 30, 2021. In addition, effective June 30, 2018, Pelican assigned and transferred its rights under the credit agreement to an affiliated entity, Permian Pelican Financial, LLC (“PPF”). The members and membership interests of PPF are the same as Pelican and PPF is a related party.

Under the revolving credit facility, the Company has the ability to borrow the lesser of 80% of eligible receivables, as defined in the credit agreement, and $1.7 million. As of September 30, 2018, there was $1.0 million outstanding under the revolving credit facility and the Company had the ability to borrow an incremental $0.7 million.

NOTE 4 — STOCK-BASED COMPENSATION

As of September 30, 2018 and December 31, 2017, we had two stock-based compensation plans with outstanding options. Only one of our plans is currently available to grant incentive stock options, non-qualified stock options and restricted stock to employees and non-employee members of the board of directors.

2017 Stock Option Plan

Effective April 4, 2017, the 2017 Stock Option Plan (the “2017 Plan”) was approved by the board of directors. On May 30, 2017, we granted options to purchase approximately 843,094 shares of common stock under the 2017 Plan which was the maximum amount authorized. The option contract term is 10 years and the exercise price is $2.00. The options vested and became exercisable immediately upon grant. The fair value of the award was estimated using a Black-Scholes fair value model. The valuation of stock options requires us to estimate the expected term of award, which was estimated using the simplified method, as the Company does not have sufficient historical exercise information. The valuation of stock option awards is also dependent on historical stock price volatility. In view of our limited trading volume, volatility was calculated based on historical stock price volatility of the Company’s peer group.

On August 20, 2018, our former chief executive officer, Shauvik Kundagrami, exercised options to purchase 250,000 shares of common stock under the 2017 Plan at an exercise price of $2.00 per share resulting in aggregate proceeds to the Company of $0.5 million. In accordance with the terms of the 2017 Plan, effective August 24, 2018, Mr. Kundagrami’s remaining options to purchase 2,928 shares of common stock under the 2017 Plan were forfeited.

Options to purchase 590,166 common shares under the 2017 Plan were outstanding and fully vested as of September 30, 2018 and December 31, 2017. We expensed stock-based compensation of $0.6 million for the full fair value of the award in May 2017.

Omnibus Incentive Plan

Subsequent to the adoption of the 2017 Plan, options are no longer permitted to be granted under the previous Omnibus Incentive Plan (the “2013 Plan”). Options to purchase 11,706 common shares under the 2013 Plan were outstanding and none of these options were vested as of September 30, 2018 and December 31, 2017. The option contract term is 10 years and the exercise price is $80.00. The options vest and are exercisable if a liquidity event, as defined in the 2013 Plan, occurs and certain conditions are met.

The aggregate unrecognized compensation cost related to these non-vested stock option awards is approximately $0.3 million (see Note 13 – Stock-Based Compensation in our Annual Report on Form 10-K for the year ended December 31, 2017 for additional detail). Such amount will be recognized in the future upon occurrence of an event that results in a vesting of the options. During the three and nine months ended September 30, 2018 and the three months ended September 30, 2017, there were no forfeited options. Options to purchase 418 shares of common stock were forfeited during the nine months ended September 30, 2017.

NOTE 5 – STOCKHOLDERS’ EQUITY

On August 7, 2018, the Company effected the Reverse Split, a 1-for-20 reverse stock split of its common stock, as approved by its Board of Directors and stockholders. Under the terms of the Reverse Split, each 20 shares of common stock issued and outstanding as of such effective date was automatically reclassified and changed into one share of common stock without further action by the stockholder. In lieu of issuing fractional shares in connection with the Reverse Split, holders received the proportionate fraction of $7.00 per share in cash. The aggregate payment made was $231.35. Shares of common stock previously issued and held as treasury shares were escheated to applicable governmental authorities and, in connection with the Reverse Split, were reinstated as outstanding shares of common stock. All share and per share amounts on this Quarterly Report on Form 10-Q, including such amounts related to options and the conversion feature of the Series A convertible preferred stock, have been retroactively restated to reflect the Reverse Split.

We filed an amendment to our certificate of formation, effective August 7, 2018, reducing our authorized common stock from 25 million to 15 million shares and reducing our authorized preferred stock from 10 million to 5 million shares.

Previously, in connection with the Recapitalization, the Company allocated 20,000 of the authorized preferred shares to be authorized Series A convertible preferred shares. Each share of Series A convertible preferred stock may be converted into 166.632 (3,332.64 pre-Reverse Split) shares of the Company’s common stock at any time at the option of the shareholder and has a liquidation preference of $1,000 per share. All shares of the Series A convertible preferred stock vote on an as-if-converted basis. See Note 6 – Controlling Shareholder and Related Party Lender for further details.

On August 20, 2018, our former chief executive officer, Shauvik Kundagrami, exercised options to purchase 250,000 shares of common stock for an exercise price of $2.00 per share, or $500,000 in aggregate.

NOTE 6 — CONTROLLING SHAREHOLDER AND RELATED PARTY LENDER

Controlling Shareholder – Pelican

On January 31, 2017 upon completion of the Recapitalization, Pelican had the power to vote the substantial majority of the Company’s outstanding common stock. As of September 30, 2018, six of our seven board members, including two of our executive officers, and our chief financial officer hold an ownership interest in Pelican.

As of September 30, 2018 and December 31, 2017, Pelican owned 17,292 shares of Series A convertible preferred stock which is convertible into 2,881,400 common shares. On an as-if-converted basis, Pelican owned approximately 75.4% and 80.7% of our common stock (excluding the impact of options) as of September 30, 2018 and December 30, 2017, respectively. The shares of Series A convertible preferred stock carry a liquidation preference of $1,000 per share or $17.3 million.

Related Party Lender – PPF

In January 2017, we entered into the Related Party Credit Facility with Pelican. Effective June 30, 2018, Pelican assigned and transferred its rights under the Related Party Credit Facility to PPF. The members and membership interests of PPF are the same as Pelican and PPF is a related party. See Note 3 – Long-Term Debt – Related Party for further detail on the Related Party Credit Facility.

In connection with our Related Party Credit Facility, during the three and nine months ended September 30, 2018, we recorded interest expense of approximately $92,000 and $0.3 million, respectively. During the three and nine months ended September 30, 2017, we recorded interest expense on the Related Party Credit Facility of approximately $69,000 and $0.7 million, respectively. Approximately $0.3 million of the aggregate expense recorded during the nine months ended September 30, 2017 related to a debt modification fee in connection with Amendment No. 2 to the credit facility which was entered into on May 23, 2017. The fee consisted of 1,200 shares of our Series A convertible preferred stock. Approximately $0.2 million of the aggregate interest expense on the Related Party Credit Facility recorded during the nine months ended September 30, 2017 was included in the obligations exchanged as part of the Recapitalization. Please see our Annual Report on Form 10-K for the year ended December 31, 2017 for a complete description of the Recapitalization, including related party transactions.

Our condensed consolidated balance sheet includes accrued interest under the Related Party Credit Facility of approximately $30,000 and $26,000 as of September 30, 2018 and December 31, 2017, respectively.

NOTE 7 — REVENUE FROM CONTRACTS WITH CUSTOMERS

Adoption of New Accounting Standards - ASU 2014-09, Revenue - Revenue from Contracts with Customers

On January 1, 2018, we adopted accounting standards update (“ASU”) 2014-09, Revenue from Contracts with Customers and all the related amendments (“new revenue standard” or “ASC 606”) to all contracts using the full retrospective method. The Company does not incur significant contract costs. The Company’s services and rental contracts are primarily short-term in nature, and therefore, based on management’s assessment, the impact of the adoption of the new revenue standard was not significant.

Revenue Recognition

Under our contracts, we generally have performance obligations to provide equipment rental, rig-up/rig-down and transportation services which constitute a series of distinct goods or services that are substantially the same and that have the same pattern of transfer to our customer. The activities included in the “other revenue” stream are not distinct as our customers would not benefit from these activities separately.

Rental Services – We are a provider of solids control systems and surface rental equipment, including centrifuges and auxiliary solids control equipment, mud circulating tanks (400 and 500 barrel capacity) and auxiliary surface rental equipment (e.g. portable mud mixing plants, containment systems, etc.). We generate revenue primarily from renting this equipment at per-day rates. In addition, we may provide personnel to operate our equipment at the customer’s location at per-day rates. We recognize revenue on rental services upon completion of each day of services.

Transportation of Equipment and Rig-Up/Rig-Down Services – We offer transportation of our rental equipment to the well site and the rig-up/rig-down of such equipment. These services are charged to the client at flat rates per job or at an hourly rate. We recognize revenue on transportation and rig-up/rig-down services at the point in time when such services have been completed.

Other – Upon request, we may sell chemicals, supplies and other consumables to our customers. We recognize revenue from the sale of consumables when they are used on site.

Chargeable Sales of Damaged Assets – Customer charges for equipment damaged beyond repair for which there is a recovery under the contract are considered asset sales and are reported within selling, general and administrative expenses net of the associated net book value for the damaged asset.

Sales and Other Related Taxes – Taxes assessed on sales transactions are not included in revenue.

The primary method used to determine standalone selling prices for our services is a “cost plus margin” approach under which we forecast the aggregate cost of satisfying a performance obligation and then add an appropriate margin for that distinct good or service. Our contracts with customers may include multiple performance obligations. For such arrangements, we allocate revenue to each performance obligation based on its relative standalone selling price.

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

We do not incur any incremental costs to obtain or fulfill our customer contracts which require capitalization under ASC 606 and have elected the practical expedient afforded to expense such costs if incurred.

The following table presents our service revenue disaggregated by revenue source (in thousands):

We maintain an allowance for doubtful accounts to reflect estimated losses resulting from the failure of customers to make required payments. On an ongoing basis, the collectability of accounts receivable is assessed based upon historical collection trends, current economic factors and the assessment of the collectability of specific accounts. We evaluate the collectability of specific accounts and determine when to grant credit to our customers using a combination of factors, including the age of the outstanding balances, evaluation of customers’ current and past financial condition, recent payment history, current economic environment, and discussions with our personnel and with the customers directly. Accounts are written off when it is determined the receivable will not be collected. If circumstances change, our estimates of the collectability of amounts could change by a material amount.

Adjustments to Previously Reported Financial Statements from the Adoption of ASC 606

In accordance with the new revenue standard requirements, there was no impact of adoption on our condensed consolidated balance sheet. The impact of adoption on our condensed consolidated statement of operations is reflected below (in thousands):

NOTE 8 – EARNINGS PER SHARE

Basic earnings per share is computed by dividing income available to common stockholders by the weighted average number of shares of common stock outstanding during the period. Diluted earnings per share is computed in the same manner as basic earnings per share except that the denominator is increased to include the number of additional shares of common stock that could have been outstanding assuming the exercise of outstanding stock options and restricted stock or other convertible instruments, as appropriate.

Due to our net loss for the nine months ended September 30, 2018 and the three months ended September 30, 2017, the effect of incremental shares is antidilutive so the diluted earnings per share will be the same as the basic earnings per share. The calculations of basic and diluted earnings per share for the three months ended September 30, 2018 and the nine months ended September 30, 2017 are shown below (in thousands, except for shares):

⁽¹⁾ The exchange of Aly Operating redeemable preferred stock into common shares and the exercise of unvested stock options under the 2013 Plan are not considered in the calculation of the numerator or denominator in the table above.

The exchange of Aly Operating redeemable preferred stock into common shares is not considered within the calculation of the numerator or denominator of diluted earnings per share because, during the month ended January 31, 2017, the Aly Operating redeemable preferred stock was not exchangeable into common shares. Effective February 1, 2017, the Aly Operating preferred stock was converted into common shares in connection with the Recapitalization and is included in our weighted average shares used for basic earnings per share. Please see our Annual Report on Form 10-K for the year ended December 31, 2017 for a complete description of the Recapitalization, including the exchange of the Aly Operating redeemable preferred stock.

Unvested stock options under the 2013 Plan are not considered within the calculation of the denominator of diluted earnings per share because they vest upon the occurrence of certain events which may or may not occur.

⁽²⁾ During the month ended January 31, 2017, the Aly Centrifuge redeemable preferred stock was convertible into 31,699 shares. Effective February 1, 2017, in connection with the Recapitalization, the Aly Centrifuge redeemable preferred stock was converted into common shares and is included in our weighted average shares used for basic earnings per share. Please see our Annual Report on Form 10-K for the year ended December 31, 2017 for a complete description of the Recapitalization, including the exchange of the Aly Centrifuge redeemable preferred stock.

Securities excluded from the computation of basic and diluted earnings per share are shown below:

_________ 

⁽¹⁾ The stock options under the 2013 Plan vest upon the occurrence of certain events as defined in the 2013 Plan. As of September 30, 2018 and 2017, the stock options were unvested.

⁽²⁾ In connection with the Recapitalization, the Aly Operating redeemable preferred stock was converted into common shares. Please see our Annual Report on Form 10-K for the year ended December 31, 2017 for a complete description of the Recapitalization, including the exchange of the Aly Operating redeemable preferred stock.

Prior to January 31, 2017, the Aly Operating redeemable preferred stock was exchangeable only upon the occurrence of certain events, as defined in the Aly Operating redeemable preferred stock agreement. Upon occurrence of such events, the Aly Operating redeemable preferred stock could have been, at the holder's option, converted into common shares. The conversion ratio, determined by a calculation defined in the agreement of which the components included trailing twelve-month financial performance and magnitude of investment in new equipment, remained undeterminable until an event would cause the Aly Operating redeemable preferred stock to become exchangeable. Effective February 1, 2017, the Aly Operating redeemable preferred stock was converted into common shares and is included in our weighted average shares used for basic earnings per share.

NOTE 9 – NEW ACCOUNTING STANDARDS

Effective January 1, 2018, we adopted the Financial Accounting Standards Board (the “FASB”) Accounting Standards Update (“ASU”) No. 2016-15, “Statement of Cash Flows - Classification of Certain Cash Receipts and Cash Payments” (“ASU 2016-15”), which addresses specific classification issues and is intended to reduce diversity in current practice regarding the manner in which certain cash receipts and cash payments are presented and classified in the consolidated statements of cash flows. The adoption of ASU 2016-15 did not have a material effect on our consolidated statements of cash flows or disclosures.

Effective January 1, 2018, we adopted the FASB ASU No. 2014-09, “Revenue from Contracts with Customers (Topic 606)” (“Topic 606”), which provides guidance for revenue recognition. Topic 606 affects any entity that either enters into contracts with customers to transfer goods or services or enters into contracts for the transfer of nonfinancial assets and supersedes the revenue recognition requirements in Topic 605, “Revenue Recognition” (“Topic 605”) and most industry-specific guidance. Topic 606’s core principle is that a company will recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which a company expects to be entitled in exchange for those goods or services. We adopted Topic 606 using the modified retrospective transition method only with respect to contracts not completed at the date of adoption. We have developed the additional expanded disclosures required; however, the adoption of Topic 606 did not have a material effect on our consolidated statements of operations, balance sheets or cash flows. See Note 7 – Revenue from Contracts with Customers for further details.

In August 2018, the FASB issued ASU No. 2018-13, “Fair Value Measurement (Topic 820) Disclosure Framework - Changes to the Disclosure Requirements for Fair Value Measurement” (“ASU 2018-13”), which modifies the disclosure requirements of fair value measurements. ASU 2018-13 is effective for us beginning January 1, 2020. Certain disclosures are required to be applied.

In February 2016, the FASB issued ASU No. 2016-02, “Leases (Topic 842)” (“ASU 2016-02”), which amends the existing accounting standards for lease accounting, including requiring lessees to recognize most leases on their balance sheets. Under ASU 2016-02, a lessee will be required to recognize assets and liabilities for leases with lease terms of more than twelve months. Lessor accounting remains substantially similar to current GAAP. In addition, disclosures of leasing activities will be expanded to include qualitative and specific quantitative information. ASU 2016-02 will be effective for annual reporting periods beginning after December 15, 2018, and early adoption is permitted. ASU 2016-02 requires a modified retrospective transition approach. As part of our assessment work to-date, we are in the process of analyzing our contracts and reviewing our policies. We have engaged external resources to assist us in our efforts to complete the analysis of potential changes to current accounting practices. We have not yet determined the effect of the ASU on our internal control over financial reporting or other changes.

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis of our financial condition and results of operations is intended to assist you in understanding our business and results of operations together with our present financial condition. This section should be read in conjunction with the condensed consolidated financial statements and the related notes thereto included elsewhere in “Item 1. Condensed Consolidated Financial Statements” in this Form 10-Q.

Cautionary Note Regarding Forward-Looking Statements

This Quarterly Report on Form 10-Q contains certain statements and information that may constitute "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Statements which are not historical in nature, including the words “anticipate,” “estimate,” “should,” “expect,” “believe,” “intend,” “may,” “project,” “plan” or “continue,” and similar expressions are intended to identify forward-looking statements.

Forward-looking statements are not assurances of future performance and actual results could differ materially from our historical experience and our present expectations or projections. Forward-looking statements involve risks and uncertainties, some of which are not currently known to us, that may cause our actual results, performance or financial condition to be materially different from the expectations of future results, performance or financial condition we express or imply in any forward-looking statements. These forward-looking statements are based on our current plans and expectations and are subject to a number of uncertainties and risks that could significantly affect current plans and expectations and our future financial condition and results. Known material factors that could cause actual results to differ materially from those in the forward-looking statements include, but are not limited to, volatility in the price of oil, fluctuations in the domestic rig count, intense competition in our industry and the other risk factors described in our Annual Report on Form 10-K for the year ended December 31, 2017.

We undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. In light of these risks, uncertainties and assumptions, the forward-looking events discussed in this Quarterly Report on Form 10-Q might not occur. We qualify any and all of our forward-looking statements entirely by these cautionary factors. You are cautioned not to place undue reliance on these statements which speak only as of the date of this Quarterly Report on Form 10-Q.

Overview of Our Business

Aly Energy Services, Inc. (“Aly Energy”, the “Company”, or “we”) is a provider of oilfield services to leading oil and gas exploration and production (“E&P”) companies operating in unconventional plays in the United States (“U.S.”). Generally, the services we offer fall within two broad categories: surface rental and solids control. Our surface rental equipment includes a wide variety of large capacity tanks with internal circulating systems, associated pumps, separators, gas busters, mud mix plants and ancillary equipment necessary to manage the flow of mud in and out of the well bore during drilling operations. We also provide environmental containment berms to safeguard against spills from the mud system. Our solids control equipment and services remove low gravity formation particulates that accumulate in mud systems during the drilling process. Once processed, the mud can be reused which eliminates unnecessary waste and disposal. Solids control equipment includes large centrifuges, shakers, cuttings dryers and ancillary components that can be integrated into a closed loop mud system.

We operate in the U.S., primarily in Texas, Oklahoma, and New Mexico. Within these states, we have a very strong footprint in the Permian Basin, one of the largest and most prolific shale plays in the U.S., and we also provide services in the Scoop/Stack region and the Eagle Ford shale.

We cultivate and maintain strong relationships with our customers which include some of the largest independent oil and gas E&P companies operating in the U.S. shale basins. Our major customers include leading companies such as EOG Resources, Inc., Pioneer Natural Resources, XTO Energy Inc., Sanchez Oil and Gas Corporation and Devon Energy Corporation.

General Trends and Outlook

Our business depends to a significant extent on the level of unconventional resource development activity and corresponding capital spending of E&P companies onshore in the U.S. These activity and spending levels are strongly influenced by the current and expected oil price. Commodity prices have increased significantly over the past two years stimulating an increase in onshore drilling and completion activity and a consequent increase in demand for our services. The average U.S. land-based drilling rig count was approximately 635 rigs in January 2017 and increased approximately 60.0% to more than 1,030 rigs by September 2018. The favorable impact of the recent increase in the rig count on demand for our services has been bolstered by a consistently high proportion of rigs drilling directional and horizontal wells. Rigs drilling directional and horizontal wells typically utilize oil-based or other sophisticated mud systems which creates demand for our specialized mud circulating tanks, pumps, containment systems, solids control and associated equipment. The proportion of rigs drilling directional and horizontal wells as a percentage of total U.S. land-based drilling rigs was approximately 92.6% and 95.8% in January 2017 and September 2018, respectively.

Looking forward to 2019, we believe that the existing commodity price environment will remain stable and the U.S. land-based drilling rig count will remain flat resulting in continued strong demand for our services. In addition, we believe that there is potential for the demand for our products and services to increase as the industry continues to invest in drilling techniques which drive efficiencies and require our products and services. Although activity increases may be marginal in the near-term, due to the tight supply of equipment that we offer, we anticipate that we will be able to continue to increase the prices we charge to our customers. Greater margins and increased margins as a percent of revenue resulting from incremental work and higher pricing will be partially offset to the extent we are required to use third-party providers of equipment and personnel. We have been operating at full utilization of our owned tanks and pumps, our anchor products, and our solids control personnel since early 2017 and we have relied on third-party providers of equipment and personnel to meet increases in demand. In order to minimize the use of third-party providers, we have initiated a capital expenditure program to invest in equipment which will meet increased demand and/or replace existing sub-rented equipment. We have committed to purchasing, new or refurbished, or fabricating telehandlers, open top tanks, 500bbl mud circulating tanks, diesel mud pumps and diesel transfer pumps for an aggregate cost of approximately $2.0 million of which approximately $1.3 million has been paid for as of September 30, 2018. Once completed, these investments should result in cost savings of approximately $0.9 million annually of which less than $0.1 million has been realized during the nine months ended September 30, 2018. We plan to continue a robust capital expenditure plan to replace sub-rented equipment throughout 2019. We believe our cash-on-hand, our positive operating cash flow, and our availability under our credit facility will be sufficient to fund the capital expenditure program.

How We Generate Revenue and the Costs of Conducting Our Business

We generate our revenue by providing drilling-related support services to E&P companies operating in some of the major onshore unconventional basins in the U.S. Our revenue streams include: (i) rental services - revenue derived from the rental of equipment and on-site operators of such equipment, (ii) rig-up/rig down services – revenue derived from the rig-up/rig-down of our equipment at the customer site, (iii) transportation services – revenue derived from the hauling of our equipment to and from the customer site, and (iv) other - revenue derived from the sale of consumable items, including chemicals. Fluctuations in the mix of services are driven primarily by the timing of and frequency with which our respective customers move their rigs from well to well and by the number of mobilizations and demobilizations of our equipment. The contribution of each revenue stream to total revenue is shown in the table below:

Our total revenues fluctuates with the utilization of and the prices we charge for our equipment and services. Utilization of our equipment is primarily determined by the U.S. land-based drilling rig count as it is typically representative of the level of activity of E&P companies. The prices we charge for our products and services depend on the relationship between the level of activity of E&P companies, or the demand of our potential and existing customers, and the supply of equipment and services available to such E&P companies from us and our competitors.

Our operating expenses consist primarily of variable costs, such as labor and third-party expenses. Labor-related expenses typically fluctuate with the utilization of our equipment and services. Expenses associated with services provided by third-parties typically increase with activity as well. Demand for our equipment has increased so significantly over the past two years that most of our available owned equipment has been fully utilized since early 2017 and we have been required to increase our available equipment fleet and our available labor resources to meet the demand from our customers. To date, we have primarily increased our available resources by sub-renting surface rental equipment and by using sub-contractors to operate our solids control equipment. To the extent we have the opportunity to generate additional revenue from increased activity, we will require the use of third-party equipment and services and third-party expenses will increase as a percent of revenue. In addition, with increased demand for oilfield services, the demand for sub-rental equipment and labor will also increase and we may experience increases in costs for third-party equipment and personnel which would further increase third-party expenses as a percent of revenue.

In order to mitigate the potential increase in third-party expenses and our overall reliance on third-party vendors, we initiated a capital expenditure plan in early 2018 to invest in new rental and transportation equipment, some of which will be fabricated in-house. During the nine months ended September 30, 2018, we took delivery of forklifts, completed the fabrication of open top tanks, and refurbished diesel mud pumps. We will see the full cost savings resulting from these investments in the fourth quarter of 2018. Throughout the remainder of 2018, we will focus on refurbishing 500bbl mud circulating tanks and fabricating diesel transfer pumps which will result in incremental cost savings beginning during the first quarter of 2019. Once all of this equipment is in service, most likely beginning in the second quarter of 2019, we project that the aggregate annual cost savings from the 2018 capital expenditure program will be approximately $0.9 million. In 2019, we plan to continue to focus on investing in equipment which will replace sub-rented equipment resulting in cost savings and reduced reliance on third-party vendors.

How We Evaluate Our Operations

We utilize multiple metrics to evaluate the results of our operations and efficiently allocate personnel, equipment and capital resources, including, but not limited to, the following:

We disclose and discuss EBITDA as a non-GAAP financial measure in our filings with the Securities and Exchange Commission. We define EBITDA as earnings (net income) before interest, income taxes, and depreciation and amortization. Our measure of EBITDA may not be comparable to similarly titled measures presented by other companies, which may limit its usefulness as a comparative measure.

We also make certain adjustments to EBITDA for (i) non-cash charges and (ii) certain expenses, such as severance, legal settlements, and professional fees and other expenses related to transactions outside the ordinary course of business, to derive a normalized EBITDA run-rate ("Adjusted EBITDA"), which we believe is a useful measure of operating results and the underlying cash generating capability of our business.

Because EBITDA and Adjusted EBITDA are not measures of financial performance calculated in accordance with GAAP, these metrics should not be considered in isolation or as a substitute for operating income, net income or loss, cash flows provided by operating, investing and financing activities, or other income or cash flow statement data prepared in accordance with GAAP.

EBITDA and Adjusted EBITDA are widely used by investors and other users of our financial statements as supplemental financial measures that, when viewed with our GAAP results and the accompanying reconciliation, we believe provide additional information that is useful to gain an understanding of our ability to service debt, pay income taxes and fund growth and maintenance capital expenditures. We also believe the disclosure of EBITDA and Adjusted EBITDA helps investors meaningfully evaluate and compare our cash flow generating capacity and performance from quarter-to-quarter and year-to-year.

Set forth below are the material limitations associated with using EBITDA and Adjusted EBITDA as non-GAAP financial measures compared to cash flows provided by and used in operating, investing and financing activities:

Management compensates for the above-described limitations in using EBITDA and Adjusted EBITDA as non-GAAP financial measures by only using EBITDA and Adjusted EBITDA to supplement our GAAP results.

The following table provides the detailed components of EBITDA and Adjusted EBITDA as we define that term for each of the three months and nine months ended September 30, 2018 and 2017 (in thousands):

Adjusted EBITDA increased by approximately $0.3 million for the three months ended September 30, 2018 from $1.0 million for the three months ended September 30, 2017 to $1.3 million for the three months ended September 30, 2017 and increased by $1.0 million to $3.4 million for the nine months ended September 30, 2018 from $2.4 million for the nine months ended September 30, 2017. The improved performance was driven primarily by increases in gross margin resulting from price increases and minimal increases in variable expenses partially offset by increases in selling, general and administrative expenses resulting from incremental headcount to strengthen internal controls and processes.

Results for the Three Months Ended September 30, 2018 Compared to the Three Months Ended September 30, 2017

The following table summarizes the change in our results of operations for the three months ended September 30, 2018 from the three months ended September 30, 2017 (in thousands):

Overview. Our results of operations improved significantly when comparing the three months ended September 30, 2018 to the three months ended September 30, 2017 due primarily to revenue increasing at a faster rate than expenses. Two of the most significant drivers of demand for our services, the price of oil and the U.S. land-based drilling rig count, increased when comparing the two periods: the price of oil increased approximately 45.0% and the U.S. land-based drilling rig count increased approximately 10.0%. As a result, demand for our products and services remained strong period-over-period. We maintained full utilization of our fleet and, due to an increasingly tight supply of equipment in 2018, we were able to significantly raise the prices we charge to our new and existing customers.

Revenue. Our revenue for the three months ended September 30, 2018 was $4.5 million, an increase of 9.6%, compared to $4.1 million for the three months ended September 30, 2017 resulting primarily from increased pricing on tanks and non-rental services such as rig-up/rig-down and hauling. When comparing the three months ended September 30, 2018 to the three months ended September 30, 2017, the pricing on tanks and non-rental services increased by more than 30% on relatively flat activity. Although robust demand for our tanks and non-rental services enabled us to increase pricing to our customers, activity remained fairly flat period-over-period because our tanks were fully utilized and, in certain circumstances, we determined that it was not cost effective to sub-rent additional tanks in order to take advantage of the increased demand. The significant pricing increases on tanks and non-rental services were partially offset by a decrease in revenue generated from other surface rental products and a change in the mix of our solids control jobs. Revenue generated by our solids control product line declined by almost 10% due to a decline in the utilization of operators. Certain major customers which require full-time solids control operators typically slow activity at year-end and resume activity in the first quarter. As certain centrifuges were released from jobs requiring personnel, we were able to redeploy them with new and existing customers resulting in flat period-over-period activity for our centrifuges.

Operating Expenses. Our operating expenses for the three months ended September 30, 2018 decreased 5.2% to $2.5 million, or 54.7% of revenue, from $2.6 million, or 63.3% of revenue, for the three months ended September 30, 2017. The slight decrease in costs was due primarily to the reduction in third-party expense for sub-contractors and other third-party services related to the change in our mix of solids control revenue away from rigs requiring operators and auxiliary sub-rented equipment towards rigs requiring centrifuges only. Most other operating expenses remained stable as there was little change in overall activity period-over-period; however, operating expenses as a percent of revenue declined significantly as we increased pricing to our customers more quickly than our costs increased.

Depreciation and Amortization. Depreciation and amortization remained fairly flat at $0.9 million for the three months ended September 30, 2018 and 2017 as the decline in depreciation and amortization from certain assets becoming fully depreciated and amortized was partially offset by the impact of capital investments.

Selling, General and Administrative Expenses. Selling, general and administrative expenses increased to $0.8 million, or 18.5% of revenue, for the three months ended September 30, 2018 compared to $0.5 million, or 12.6% of revenue, for the three months ended September 30, 2017. Selling, general and administrative expenses consist of overhead costs which we generally consider to be fixed. The year-over-year increase of $0.3 million, or 61.1%, is primarily due to increases in compensation to existing employees and by an increase in headcount of selling, general and administrative employees to an average of 15 employees during the three months ended September 30, 2018 from 11 employees during the three months ended September 30, 2017. With the improved financial results we are experiencing, we have increased headcount in order to facilitate the segregation of duties and to strengthen our internal controls. In addition, non-recurring and non-cash items increased by approximately $97,000 to an aggregate expense of approximately $75,000 for the three months ended September 30, 2018 from an aggregate benefit of $12,000 for the three months ended September 30, 2017 (see further discussion in “How We Evaluate Our Operations” section above). These increases were partially offset by a decline in third-party audit and accounting fees as the expenses incurred in 2017 to catch up on prior year filings did not recur in 2018.

Interest Expense, Net. Interest expense, net, consisting of interest on insurance financing and other miscellaneous interest expense, was approximately $3,000 for the three months ended September 30, 2018 and approximately $2,000 for the three months ended September 30, 2017.

Interest Expense – Related Party. During the three months ended September 30, 2018 and 2017, we recorded approximately $92,000 and $69,000, respectively, of interest expense on borrowings under the Related Party Credit Facility. The period-over-period increase is primarily due to an increase in borrowings under the facility.

Income Taxes. The difference in the effective tax rate from the statutory rate is due to our continued full valuation allowance on net deferred tax assets. Income tax expense and benefit is related to the Texas Margin Tax. The Company has sufficient NOL carryforwards to offset federal income tax and other state income taxes.

Results for the Nine Months Ended June 30, 2018 Compared to the Nine Months Ended June 30, 2017

The following table summarizes the change in our results of operations for the nine months ended September 30, 2018 from the nine months ended September 30, 2017 (in thousands):