10-K 1 wttr-20171231x10k.htm 10-K wttr_Current_Folio_10K

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-K

 

(Mark One)

 

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

 

For the fiscal year ended December 31, 2017.

 

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 001-38066

 

Select Energy Services, Inc.

 

(Exact name of registrant as specified in its charter)

 

 

 

 

Delaware

    

81‑4561945

(State or Other Jurisdiction of Incorporation or Organization)

 

(I.R.S. Employer Identification No.)

 

 

 

515 Post Oak Boulevard, Suite 200

Houston, Texas

 

77027

(Address of Principal Executive Offices)

 

(Zip Code)

 

Registrant’s telephone number, including area code (713) 235-9500

 

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

 

 

 

 

Title of each class

    

Name of each exchange on which registered

 

 

 

Class A Common Stock $0.01 par value

 

New York Stock Exchange

 

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

 

NONE

 

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

 

 

 

 

Yes  

 

No  

 

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.

 

 

 

Yes  

 

No  

 

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 registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

 

 

 

 

Yes  

 

No  

 

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, 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  

 

No  

 

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§299.405 of this chapter) is not contained herein, and will not be contained, to the best of the 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, a smaller reporting company or an emerging growth company.  See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

 

 

 

 

 

Large accelerated filer

Accelerated filer

Non-accelerated filer (Do not check if a smaller reporting company)

Smaller reporting company

Emerging growth company

 

 

 

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.

 

Indicate by check mark whether the registrant is a shell company (as defined by Rule 12b-2 of the Exchange Act).

 

Yes  

 

No  

 

The aggregate market value of the voting and non-voting common stock held by non-affiliates of the registrant computed as of June 30, 2017 (the last business day of the registrant’s most recent completed second fiscal quarter) based on the closing price of the Class A common stock on the New York Stock Exchange was $322.1 million.  There were 59,290,665, 6,731,839 and 40,331,989 shares of the registrant’s Class A, Class A-2 and Class B common stock, respectively, outstanding as of March 15, 2018.

 

Documents Incorporated by Reference:

 

Portions of the registrant’s definitive proxy statement for the 2018 annual meeting of stockholders, to be filed no later than 120 days after the end of the fiscal year, are incorporated by reference into Part III of this Annual Report on Form 10-K.

 

 

 


 

Table of Contents

 

 

Page

PART I 

 

 

 

 

Item 1. 

Business

4

 

 

 

Item 1A. 

Risk Factors

26

 

 

 

Item 1B. 

Unresolved Staff Comments

53

 

 

 

Item 2. 

Properties

53

 

 

 

Item 3. 

Legal Proceedings

54

 

 

 

Item 4. 

Mine Safety Disclosure

54

 

 

PART II 

 

 

 

 

Item 5. 

Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

55

 

 

 

Item 6. 

Selected Financial Data

56

 

 

 

Item 7. 

Management’s Discussion and Analysis of Financial Condition and Results of Operations

59

 

 

 

Item 7A. 

Quantitative and Qualitative Disclosures About Market Risk

81

 

 

 

Item 8. 

Financial Statements and Supplementary Data

82

 

 

 

Item 9. 

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

82

 

 

 

Item 9A. 

Controls and Procedures

82

 

 

 

Item 9B. 

Other Information

82

 

 

 

PART III 

 

 

 

 

Item 10. 

Directors, Executive Officers and Corporate Governance

83

 

 

 

Item 11. 

Executive Compensation

83

 

 

 

Item 12. 

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

83

 

 

 

Item 13. 

Certain Relationships and Related Transactions, and Director Independence

83

 

 

 

Item 14. 

Principal Accountant Fees and Services

83

 

 

 

PART IV 

 

 

 

 

Item 15. 

Exhibits and Financial Statement Schedules

83

 

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PART I

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

The information in this Annual Report on Form 10-K includes “forward‑looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements, other than statements of historical fact, included in this Annual Report regarding our strategy, future operations, financial position, risks, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward‑looking statements. When used in this Annual Report, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project,” “preliminary,” “forecast” and similar expressions or variations are intended to identify forward‑looking statements, although not all forward‑looking statements contain such identifying words. When considering forward‑looking statements, you should keep in mind the cautionary statements included in this Annual Report. These forward‑looking statements are based on management’s current belief, based on currently available information, as to the outcome and timing of future events. Important factors that could cause actual results to differ materially from those in the forward‑looking statements include, but are not limited to, those summarized below:

the ultimate outcome and results of integrating our operations with the operations of Rockwater (as defined herein);

the effects of our business combination with Rockwater, including the combined company’s future financial condition, results of operations, strategy and plans;

potential adverse reactions or changes to business relationships resulting from the completion of the Rockwater Merger (as defined herein);

expected benefits from the Rockwater Merger and the ability of the combined company to realize those benefits;

the results of any merger‑related litigation, settlements and investigations;

the level of capital spending by U.S. and Canadian oil and gas companies;

trends and volatility in oil and gas prices;

demand for our services;

regional impacts to our business, including our key infrastructure assets within the Bakken;

our level of indebtedness and our ability to comply with covenants contained in our Credit Agreement (as defined herein) or future debt instruments;

our access to capital to fund expansions, acquisitions and our working capital needs and our ability to obtain debt or equity financing on satisfactory terms;

our safety performance;

the impact of current and future laws, rulings and governmental regulations, including those related to hydraulic fracturing, accessing water, disposing of wastewater and various environmental matters;

our ability to retain key management and employees;

the impacts of competition on our operations;

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our ability to hire and retain skilled labor;

delays or restrictions in obtaining permits by us or our customers;

constraints in supply or availability of equipment used in our business;

the impacts of advancements in drilling and well service technologies;

changes in global political or economic conditions, generally, and in the markets we serve;

accidents, weather, seasonality or other events affecting our business; and

the other risks identified in this Annual Report including, without limitation, those under the headings “Item 1A. Risk Factors,” “Item 1. Business,” “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” (“MD&A”) and “Item 13. Certain Relationships and Related Transactions, and Director Independence.”

These factors are not necessarily all of the important factors that could cause actual results to differ materially from those expressed in any of our forward‑looking statements. Other unknown or unpredictable factors also could have material adverse effects on our future results. Our future results will depend upon various other risks and uncertainties, including those described elsewhere in this Annual Report. Readers are cautioned not to place undue reliance on forward‑looking statements, which speak only as of the date hereof. We undertake no obligation to update or revise any forward‑looking statements after the date they are made, whether as a result of new information, future events or otherwise. All forward‑looking statements attributable to us are qualified in their entirety by this cautionary statement.

References Within This Annual Report

As used in Part I of this Annual Report on Form 10-K, unless the context otherwise requires, references to the ”Company,” ”we,” ”our,” ”us” or similar expressions refer (1) for time periods prior to our December 2016 private placement of 16,100,000 shares of our Class A-1 common stock at $20.00 per share (the “Select 144A Offering”) and the related corporate reorganization transactions to Select Energy Services, LLC (“Select LLC”) and SES Holdings, LLC (“SES Holdings”) and their consolidated subsidiaries, (2) for time periods after the Select 144A Offering and the related corporate reorganization transactions and prior to the Rockwater Merger and the related corporate reorganization transactions, to Select Energy Services, Inc. (“Select Inc.”) and its consolidated subsidiaries and (3) after the Rockwater Merger and the related corporate reorganization transactions, to Select Inc. and its consolidated subsidiaries, including those subsidiaries acquired in the Rockwater Merger. Additionally, prior to the consummation of the Rockwater Merger and the related corporate reorganization transactions, “Rockwater” refers to Rockwater Energy Solutions, Inc. and its consolidated subsidiaries and “Rockwater LLC” refers to Rockwater Energy Solutions, LLC and its consolidated subsidiaries. Following the consummation of Rockwater Merger and the related corporate reorganization transactions “Rockwater” refers to Select Energy Solutions (RW), Inc. and its consolidated subsidiaries and “Rockwater LLC” refers to Rockwater Energy Solutions, LLC and its consolidated subsidiaries.

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ITEM 1.              BUSINESS

We are a leading provider of total water management and chemical solutions to the unconventional oil and gas industry in the United States and Western Canada. We were formed as a Delaware corporation in November 2016. Within the major shale plays in the United States, we believe we are a market leader in sourcing, transfer (both by permanent pipeline and temporary hose) and temporary containment of water prior to its use in drilling and completion activities associated with hydraulic fracture stimulation or “fracking,” which we collectively refer to as “pre‑frac water services”. In addition, we provide testing and flowback services immediately following the well completion. In most of our areas of operations, we also provide additional complementary water‑related services that support oil and gas well completion and production activities, including monitoring, treatment, hauling, water recycling and disposal. We also manufacture a full suite of specialty chemicals used in well completions, and we provide chemicals needed by our customers to help increase oil and gas production and lower costs over the extended life of a typical well. We have historically generated a substantial majority of our revenues through providing total water solutions to our customers, and we believe we are the only company that provides total water solutions together with complementary chemical products and related expertise, which we believe gives us a unique competitive advantage in our industry.

Water is essential to the development and completion of unconventional oil and gas wells, where producers rely on fracking to stimulate the production of oil and gas from dense subsurface rock formations. The volume of water required to economically produce tight oil and gas reserves in the United States and Canada has grown more than tenfold over the past five years. Water and related services comprise a large and growing portion of our customers’ drilling and completion costs. In support of new well development, we source, transfer, provide containment of and treat the water used by our customers in the well completion process. The fracking process involves the injection of large volumes of water and proppant (typically sand) together with chemicals under high pressure, through a cased and cemented wellbore into targeted subsurface formations thousands of feet below ground to fracture the surrounding rock. Our completion chemicals are blended with water to improve the transport and placement of proppant in targeted zones within the producing formation. The induced fractures near the wellbore allow hydrocarbons to flow into the wellbore for extraction. Our team of chemists and research and development personnel work with our customers to optimize the frac fluid system. Up to fifty percent of the water pumped into the well during the fracking process returns as “flowback” during the first several weeks following the well completion process, and a large percentage of the remainder, plus pre‑existing water in the formation, is recovered as produced water over the life of the well. This flowback and produced water must be captured, contained and either disposed of in an environmentally safe manner, or treated and recycled for reuse in subsequent frack jobs. We provide services that support the operator’s management of flowback and produced water. After the fracking process is completed, we provide a variety of services related to the initial phase of the flowback and production operations that complement the longer‑term oil and gas production activities, including designing and executing chemical treatment programs to improve well productivity, extend the useful life of wells and reduce production costs.

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The diagram below illustrates the primary water solutions and oilfield chemicals services we provide during the completion and production cycle of a horizontal well:

Picture 2

As the development of unconventional reservoirs has evolved over the past decade, the total volumes of water required in the fracking process have grown dramatically. Management estimates that the completion of a horizontal well in 2009 required an average of approximately 75,000 barrels of water or approximately 575 tank truck loads. Today, current horizontal well completions can require in excess of 500,000 barrels per well or roughly 3,850 tank truck loads. Multi‑well pad completions can require in excess of 5 million barrels of water per pad, or the equivalent of 38,500 tank truck loads. Significant mechanical, logistical, environmental and safety issues related to the transfer and subsequent containment of such large volumes via tank truck have resulted in tank trucks no longer representing a viable solution for the transport of frack water. Accordingly, E&P companies have shifted their pre-frac operational focus away from traditional tank truck operators and small, local water service providers, to larger, regional and national players, like us, who have the expertise, technology and scale to provide high quality, reliable, comprehensive and environmentally sound water services.

The total volumes of flowback and produced water are even greater―by some estimates, the U.S. oil and gas industry today produces over 20 billion barrels of water per year and this volume is likely to grow. We believe the industry will increasingly turn to companies like us to help cost effectively manage produced water in an environmentally responsible way.

We believe our broad geographic footprint, comprehensive suite of water services, inventory of water sources and permanent and temporary pipeline infrastructure position us to be a leading provider of water solutions in all of the shale plays that we serve. We have well‑established field operations in what we believe to be core areas of many of the most active shale plays in the United States and Canada, including the Permian Basin, SCOOP/STACK, Bakken, Eagle Ford, Haynesville, Marcellus, Utica, Rockies (DJ/Niobrara, Powder River and Uinta), other Mid‑Continent (“MidCon”) basins (Woodford, Barnett, Fayetteville, Granite Wash and Mississippian) and Western Canada. Our broad footprint enables us to service the majority of current domestic unconventional drilling and completions activity. We estimate that over 80% of all currently active U.S. onshore horizontal rigs are operating in our primary service areas and anticipate that the vast majority of rigs that will be deployed in the near‑ to medium‑term will be situated in these areas. In particular, we have established a strong position in the Permian Basin, which is presently our largest operating region,

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and where producers are continuing to invest significant capital as commodity prices continue to recover from recent lows.

We seek to be a comprehensive provider of total water management and chemical solutions for our customers in most of our areas of operations. We have the capability to provide all of the pre-frac water services and many of the complementary chemicals our customers require in their drilling and completion activities, including the sourcing, transferring, containing, treatment, testing and monitoring of water. We also offer various complementary water‑related services that support oil and gas completion and production activities, including well testing, flowback, post-frac fluid hauling, pipeline gathering, treatment, recycling and disposal of water. In addition, we develop and manufacture a full suite of production chemicals used to enhance performance over the life of a well.

On the pre-frac side our Water Solutions segment’s inventory of water sources is a key competitive advantage that enables us to offer our customers reliable access to the volume of water essential for fracking operations. Water sources are often difficult to locate, acquire and permit, particularly in the quantities needed for multi‑well pad development programs. We have spent years obtaining strategic water sources and have secured permits or long‑term access rights to approximately 1.5 billion barrels of water annually from hundreds of sources, including large scale sources such as the Brazos, Missouri, Navasota, Ohio, Rio Grande, Sabine, San Antonio and Washita Rivers. In the Bakken, for example, we believe we have established a market leading position by securing three governmental permits which enable us to withdraw up to 100 million barrels of water annually from the Missouri River and Lake Sakakawea in North Dakota. Fresh water access cannot be easily replicated on Lake Sakakawea today as there are multiple environmental and regulatory conditions that must be met before an industrial water intake location can be built. New permits will also not be granted within 25 miles of an intake location associated with an existing permit. We have three of the five existing permits off Lake Sakakawea. In addition to surface water rights, groundwater resources are a key component of our extensive water portfolio. These sources have been secured or developed within our Water Solutions group and are designed with dedicated containment and transfer logistics to offer a complete water management solution. The first step in procuring a water source is identifying an area of interest based on anticipated drilling and completion activity as a result of lease activity, applications for permits and industry sources. After a specific water source is identified, we perform an assessment of the particular prospective source, including confirming availability, regulatory status, and any limitations on potential water rights. We use our AquaView® technology to quantify volumes and flow rates to verify current and potential water availability and volumes. After confirming the relevant ownership information, we begin negotiations with the applicable landowner or holder of the water rights. After finalizing the agreements and access rights, our team will obtain necessary regulatory approvals, permits and rights‑of‑way as needed based on the regulatory authorities involved and individual circumstances. Going forward, we believe that our expertise and relationships in water sourcing will provide us with a competitive advantage in identifying and securing additional sources of water. Additionally, water is increasingly becoming sourced through the reuse of produced or flowback water from existing wells that has been subjected to various treatment or fresh water blending options. We have a dedicated team of individuals focused on developing water treatment and reuse services to our customers and although water reuse has been a relatively small percentage of our revenue to‑date, we believe demands for our water reuse services will increase as water demands increase, regulatory restrictions increase, disposal options decrease, water treatment costs decline and operators reevaluate the reuse of treated flowback and produced water in their completion programs.

We also manage the transfer of water from the source, between containments and ultimately to the wellsite for well completion. We have invested significant capital in temporary pipe, including approximately 1,400 miles of lay‑flat hose, and other related assets. Our lay‑flat hose provides a flexible water transfer solution and can be customized to fit a specific project. After the completion of a project, lay‑flat hose can be quickly and cost‑effectively removed and redeployed for a new project. These investments enable us to provide our customers with temporary water transfer systems that have substantially lower risk of leaks or spills compared to many alternative temporary piping options. We believe our expansive inventory of lay‑flat hose, in combination with our customers’ preference for this temporary water transfer method, positions us to be a market leader for this class of water transfer services. To support our water sourcing and transfer services, we have also made significant investments in strategic permanent pipelines that provide reliable and cost effective water delivery. Our most significant pipeline assets are located in the Bakken and allow us to take advantage of our water permits in that region. Our Bakken pipelines consist of two active underground pipeline systems, the Charlson and the Iverson systems, in McKenzie County, North Dakota that can currently deliver up to 62 million barrels of fresh water per year. We are in the process of developing a third underground pipeline to support Williams

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County and western Mountrail County in North Dakota that would allow us to fully utilize our annual water rights in this region. We have signed long‑term contracts supported by Areas of Mutual Interest with major Bakken producers that we believe will use a significant portion of our current pipeline capacity. We have also made investments outside of the Bakken, including our pipeline serving the SCOOP area of Oklahoma, the “Pecan Hill Pipeline,” and our pipeline serving the Haynesville, the “IP Pipeline.” Additionally, with the GRR Acquisition (as defined below) we acquired rights to a vast array of fresh, brackish and effluent water sources with access to significant volumes of water annually and water transport infrastructure, including over 1,200 miles of temporary and permanent pipeline infrastructure and related storage facilities and pumps, all located in the northern Delaware Basin portion of the Permian Basin.

In addition to water sourcing and transfer, our Water Solutions segment offers various complementary water‑related services that support oil and gas completion and production activities. Before and during the completion phase of a well, along with water sourcing and transfer, we offer water containment, monitoring and treatment solutions. Following the completion process, we provide flowback and well testing services, flowback and produced water hauling, pipeline gathering and disposal services and water treatment and recycling solutions relating to the potential reuse of flowback and produced water for new well completions. We support our customers across the life cycle of a well from completion to production and our comprehensive technical expertise related to water solutions management uniquely positions us relative to other water solutions providers to provide our customers comprehensive service solutions designed to maximize well performance, reduce costs and increase efficiencies while reducing the environmental impacts of their resource development.

Our Oilfield Chemicals segment develops, manufactures and provides a full suite of chemicals utilized in hydraulic fracturing, stimulation, cementing and well completions, including polymers that create viscosity, crosslinkers, friction reducers, surfactants, buffers, breakers and other chemical technologies, to leading pressure pumping service companies in the United States. Our production chemicals solutions, which can be applied to producing wells throughout their producing lives, are applied to underperforming wells in order to enhance well performance and reduce production costs through the use of production treating chemicals, corrosion and scale monitoring, chemical inventory management, well failure analysis and lab services. Our product lines support the full range of fluid systems utilized primarily in the completion and development of unconventional resources. The use of automated communications systems combined with direct‑to‑wellsite delivery ensures seamless product availability for our customers, while our chemical expertise enables us to deliver a customized suite of products to meet customers’ technical and economical product needs. Our expertise in frac chemistry also positions us to support our customers in developing programs to reuse produced and flowback water as an alternative to disposal. In addition to our product offering, we provide inventory management services, including procurement, warehousing and delivery services. We have two primary manufacturing facilities in Texas, five regional distribution centers and 29 heavy chemical transport trucks and provide products to our customers in all major U.S. shale basins. Rockwater will also have the first in-basin manufacturing facility of emulsion polymers (friction reducers) in our industry. The in-basin manufacturing facility is strategically located in the Permian Basin which will provide a strategic advantage of being able to reduce our overall costs of raw materials that can now be delivered directly to the basin by rail. 

We also offer our customers various ancillary services through our Wellsite Services segment. Through our subsidiary, Peak Oilfield Services, LLC (“Peak”), we provide workforce accommodations and surface rental equipment supporting oil and gas drilling, completion and production operations. Through our subsidiary, Affirm Oilfield Services, LLC (“Affirm”), we provide crane and logistics services, wellsite and pipeline construction and various field services. Operating under Rockwater LLC, we also offer sand hauling and logistics services in the Rockies and Bakken regions, as well as water transfer, containment, fluids hauling and other rental services in Western Canada. We provide our Wellsite Services to a wide range of customers in many of the most active shale plays or basins in the United States and Canada.

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We maintain a culture that prioritizes safety, the environment and our relationship with the communities in which we operate. We place a strong emphasis on the safe execution of our operations, including safety training for our employees and the development of a variety of safety programs designed to make us a market leader in safety standards. Further, our safety recognition program incentivizes employees throughout our organization to focus on conducting operations in accordance with our strict safety standards. In addition, we work closely with federal, state and local governments and community organizations to help ensure that our operations comply with legal requirements and community standards. We believe that our customers will select their service providers based in part on the quality of their safety and compliance records, and therefore, we will continue to make significant investments to be a market

leader in this area.

Recent Developments

Rockwater Merger

On November 1, 2017, we completed the transactions (the “Rockwater Merger”) contemplated by the Agreement and Plan of Merger, dated as of July 18, 2017 (the “Merger Agreement”), by and among us, SES Holdings, Raptor Merger Sub, Inc., a Delaware corporation and our wholly owned subsidiary, Raptor Merger Sub, LLC, a Delaware limited liability company and an indirect wholly owned subsidiary of SES Holdings, Rockwater and Rockwater LLC. Pursuant to the Merger Agreement, we combined with Rockwater in a stock‑for‑stock transaction in which we issued approximately 25.9 million shares of our Class A common stock, 6.7 million shares of our Class A‑2 common stock and 4.4 million shares of our Class B common stock to the former holders of Rockwater common stock and a unit‑for‑unit transaction in which SES Holdings issued approximately 37.3 million common units in SES Holdings  (each, an “SES Holdings LLC Unit”) to the former holders of units in Rockwater LLC (each, a “Rockwater LLC Unit”).

Rockwater was incorporated as a Delaware corporation in March 2017. Prior to the Rockwater Merger, Rockwater was a holding company whose sole material asset consisted of a membership interest in Rockwater LLC. Rockwater’s predecessor corporation was formed as a Delaware corporation in June 2011 and converted into Rockwater LLC in March 2017.

Resource Water Acquisition

On September 15, 2017, we completed our acquisition (the “Resource Water Acquisition”) of Resource Water Transfer Services, L.P. and certain other affiliated assets (collectively, “Resource Water”). Resource Water provides water transfer services to E&P operators in West Texas and East Texas. Resource Water’s assets include 24 miles of layflat hose as well as numerous pumps and ancillary equipment required to support water transfer operations. Resource Water has longstanding customer relationships across its operating regions which are viewed as strategic to our water solutions business.

Initial Public Offering

On April 20, 2017, the registration statement on Form S‑1 (File No. 333‑216404) relating to our initial public offering (the “IPO”) was declared effective by the SEC. The IPO closed on April 26, 2017, at which time we issued and sold 8,700,000 shares of Class A common stock at a price to the public of $14.00 per share. We received cash proceeds of approximately $114.2 million from this transaction, net of underwriting discounts and commissions. On May 10, 2017, the underwriters exercised in full their option to purchase an additional 1,305,000 shares of Class A common stock at a price to the public of $14.00 per share. We received cash proceeds of approximately $17.1 million, net of underwriting discounts and commissions and estimated offering expenses, from the sale of such additional shares pursuant to the underwriters’ option. We incurred costs of approximately $2.8 million related to the IPO.

Crescent Merger

On March 31, 2017, Rockwater acquired Crescent Companies, LLC (‘‘Crescent’’), a company that provides water and fluid management solutions to E&P companies principally in the Mid Continent, Marcellus/Utica, Eagle Ford and Permian basins (the ‘‘Crescent Merger’’). A majority of Crescent’s revenue is derived from providing total water and fluid management solutions. The consideration for the Crescent Merger consisted of equity securities and the repayment of Crescent’s outstanding indebtedness, which was approximately $39.3 million, using borrowings under

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Rockwater’s credit facility. Rockwater issued 4,105,998 shares of Rockwater Class A Common Stock  and Rockwater LLC issued 5,693,258 Rockwater LLC Units and an equivalent number of shares of Rockwater Class B Common Stock to the owners of Crescent.

GRR Acquisition

On March 10, 2017, we completed our acquisition (the “GRR Acquisition”) of Gregory Rockhouse Ranch, Inc. and certain other affiliated entities and assets (collectively, the “GRR Entities”). The GRR Entities provide water and water‑related services to E&P companies in the Permian Basin and own and have rights to a vast array of fresh, brackish and effluent water sources with access to significant volumes of water annually and water transport infrastructure, including over 1,200 miles of temporary and permanent pipeline infrastructure and related storage facilities and pumps, all located in the northern Delaware Basin portion of the Permian Basin. The total consideration we paid for this acquisition was $59.6 million, with $53.0 million paid in cash,  $5.5 million paid in shares of Class A common stock, subject to customary post‑closing adjustments, and $1.1 million in assumed tax liabilities to the sellers. We funded the cash portion of the consideration for the GRR Acquisition with $19.0 million of cash on hand and $34.0 million of borrowings under our Previous Credit Facility (as defined below), which we repaid with a portion of the net proceeds of the IPO. We believe this acquisition has significantly enhanced our position in the Permian Basin.

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Description of Business Segments

Following the completion of the Rockwater Merger, we offer our services through the following three operating segments: (i) Water Solutions, (ii) Oilfield Chemicals and (iii) Wellsite Services.

Water Solutions

Our Water Solutions segment is operated primarily under our subsidiary, Select LLC, and provides water‑related services to customers that include major integrated oil companies and independent oil and natural gas producers. These services include: the sourcing of water; the transfer of the water to the wellsite through permanent pipeline infrastructure and temporary hose; the containment of fluids off‑ and on‑location; measuring and monitoring of water; the filtering and treatment of fluids, well testing and handling of flowback and produced formation water; and the transportation and recycling or disposal of drilling, completion and production fluids.

Service Lines

Our Water Solutions operating segment is divided into the following service lines:

Water Sourcing.  Our water sourcing service line helps E&P companies source water used for drilling and completion operations from our surface, ground and industrial water sources. Specifically, through a portfolio of contracts with and permits from regulatory bodies, corporations and individual landowners, we have secured rights to approximately 1.5 billion barrels of water annually from hundreds of sources, a number which varies over time, including large scale sources such as the Brazos, Missouri, Navasota, Ohio, Rio Grande, Sabine, San Antonio and Washita Rivers. In the Bakken, we have three governmental permits that enable us to withdraw up to 100 million barrels of water annually from the Missouri River and Lake Sakakawea in North Dakota. Fresh water access cannot be easily replicated on Lake Sakakawea today as there are multiple environmental and regulatory conditions that must be met before an industrial water intake location can be built. New permits will also not be granted within 25 miles of an intake location associated with an existing permit. We have three of the five existing permits off Lake Sakakawea. Additionally, the recently acquired GRR Entities have rights to a vast array of fresh, brackish and effluent water sources with access to significant volumes of water annually. In addition to primary frac water sourcing, we also source brine water and other completion fluids.

Water Transfer.  Our water transfer service line provides high‑volume, high‑rate water transfer services through permanent pipeline systems and temporary pipe systems. This service is utilized to transfer water from a source to a containment location on or off the wellsite, from the containment directly to the well to support completion operations, and, in certain circumstances, directly from the source to the well. Our assets include more than 110 miles of operational underground pipeline, approximately 1,400 miles of lay‑flat hose and approximately 1,000 high‑rate water transfer pumps. Additionally, the recently acquired GRR Entities own significant water transport infrastructure, including over 1,200 miles of temporary and permanent pipeline infrastructure and related storage facilities and pumps, all located in the northern Delaware Basin portion of the Permian Basin. The Rockwater Merger added Rockwater’s sizable fleet of small and large diameter pipe and hose and pumps to our water transfer service line and extended our water transfer service capabilities across North America. Our permanent pipeline systems are located in the Bakken, the SCOOP and the Haynesville, as described in more detail below.

Bakken: We have invested over $30.0 million in the Charlson Pipeline and the Iverson Pipeline in the Bakken located in McKenzie County, North Dakota, and we are developing a third pipeline system that will serve Williams County and western Mountrail County. The Charlson pipeline system is located on the eastern side of McKenzie County, North Dakota, and consists of 32 miles of operational pipeline. The Iverson pipeline system is located in eastern McKenzie County, North Dakota, and consists of 58 miles of operational pipeline. Of the approximately 90 miles of underground pipeline systems, we own 38 miles and have contractual rights to access the remaining 52 miles. The development of the third permit began in late 2017 and will allow us to utilize 100 million barrels of fresh water per year across the three systems.

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SCOOP: Through our interest in a joint venture with Access Midstream (subsequently merged with Williams Partners), we own a nine‑mile, underground fresh water delivery pipeline in Grady County, Oklahoma in what we believe to be the core of the SCOOP, with an additional 23 miles of sour gas pipeline that can be subsequently converted to deliver fresh water. The source for this pipeline system originates from the Washita River, a reliable water source in an otherwise dry and drought‑prone region of Oklahoma. We are currently permitted by the Oklahoma Water Resources Board to withdraw 10.8 million barrels of water per year from the river, in excess of the pipeline’s current physical throughput capacity of 9.2 million barrels per year.

Haynesville: We own an approximately 12‑mile underground fresh water delivery pipeline in De Soto Parish, Louisiana, which transports effluent from a pump station at International Paper’s Mansfield Plant Outfall No. 1 to five delivery points within the Holly Field for use in fracking operations. The IP Pipeline is located in what we believe is the core acreage of the Haynesville shale.

Our lay‑flat hose provides a flexible water transfer solution and can be customized to fit a specific project. After the completion of a project, lay‑flat hose can be quickly and cost‑effectively removed and redeployed for a new project, including projects in different geographic regions. Lay‑flat hose has a significantly lower risk of spills than most other types of temporary jointed‑pipe as a result of the strength and durability of the hose as well as the secure nature of any coupling joints used to connect multiple sections of hose. We believe the average length of lay‑flat hose used in a project is approximately 5 miles, but the length can vary from as little as a few hundred feet to as much as 75 miles for a comprehensive water management program. Our lay‑flat hose consists of 8 inch, 10 inch and 12 inch diameter segments. Depending on the requirements of a project, lay‑flat hose may run from a water source directly to a containment area or wellsite or from containment area to containment area. Our customers generally prefer lay‑flat hose to alternative temporary piping options due to the cost‑effectiveness, customizability and reduced risk of spills.

Water Containment.  We are the largest provider of high‑capacity above ground storage tanks (“ASTs”) in North America with an inventory offering water storage capacity between 4,500 and 60,000 barrels per tank with remote monitoring capability in every major U.S. basin and Western Canada. Our ASTs provide a low cost containment alternative to frac tanks and support our water treatment and reuse strategy that we bundle with our water transfer and water reuse services to provide enhanced water management solutions to our customers. A 40,000 barrel AST can be delivered by three trucks and be installed in half a day, and replaces 80 500‑barrel frac tanks. Our modular tank design allows for 20 different tank configurations to meet each customer’s individual needs, and we also offer nested tanks for complete secondary containment.

Water Treatment and Recycling.  Our water treatment and recycling service line works with oil and gas producers to treat water utilized in the drilling, completion and production processes. Additionally, we offer recycling services for the reuse of flowback, produced or otherwise impaired water for reuse in new well completions. Specifically, we offer water treatment and recycling solutions ranging from basic filtration solutions to the application of chemical disinfection and more advanced technologies, including oil removal, iron removal and the removal of other contaminants. These solutions are offered through in‑house equipment and expertise, as well as with outside strategic relationships and investments.

Well Testing and Flowback.  Our well testing and flowback service line provides highly trained personnel and state‑of‑the‑art equipment and technologies to perform a multitude of services relating to the completion and production of oil, gas, condensate and water, including frac support, frac plug drill‑out, flowback, well testing and lease operating. These services are critical to the completion and production phase of a well, as it provides the customer with initial well productivity data which ultimately impacts a reservoir’s capacity to produce hydrocarbons, such as oil, gas and condensate. Our traditional well testing and hydraulic equipment can service a multitude of operational scenarios, such as high and low temperature, high and low pressure, high hydrogen sulfide concentration and high volume. Currently, we own approximately 280 equipment spreads to support this broad range of services.

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Fluid Hauling.  Our fluid hauling service line transports and stores water and various drilling, completion and production fluids utilizing our fleet of vacuum trucks, winch trucks, hydrovac trucks, and related assets, such as frac tanks. Currently, we own and lease approximately 200 tractors and own approximately 990 frac tanks.

Fluid Disposal.  We own 18 salt water disposal (“SWD”) wells with a daily maximum permitted disposal volume of approximately 300,000 bpd. Our SWD wells are located in the Eagle Ford (6), Permian (4), Haynesville (3), Marcellus (2), MidCon (2) and Rockies (1) regions.

Geographic Areas of Operation

We offer our Water Solutions services in most of the major unconventional shale plays in the continental U.S., as illustrated by a “” in the chart below.

 

 

 

 

 

 

 

 

 

 

Geographic Region

Services Provided

Permian

MidCon

Bakken

Eagle Ford

Marcellus /
Utica

Haynesville

Rockies

Water Sourcing

Water Transfer

Water Containment

Water Monitoring

Water Treatment and Recycling

Well Testing and Flowback

*

Fluid Hauling

*

Frac Tanks

*

Fluid Disposal


*In these regions, we have retained facilities but are not currently conducting operations.

Customers

Our Water Solutions customers primarily include major integrated and independent U.S. and international oil and gas producers.

Competition

Many large domestic and international oilfield services companies offer some water‑oriented and environmental services, though these are generally ancillary to their core businesses. As a result, the water solutions industry is highly fragmented and our main competitors are typically smaller or mid‑sized and often private service providers that focus on water solutions and logistical services across a narrow geographic range. We seek to differentiate ourselves from our competitors by delivering the highest‑quality services and equipment possible, coupled with superior execution and operating efficiency in a safe working environment.

Oilfield Chemicals

Our Oilfield Chemicals segment is operated primarily under our subsidiary, Rockwater LLC, and develops, manufactures and provides a full suite of chemicals utilized in hydraulic fracturing, stimulation, cementing and well completions, including polymers that create viscosity, crosslinkers, friction reducers, surfactants, buffers, breakers and other chemical technologies, to leading pressure pumping service companies in the United States. We also provide

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production chemicals solutions, which are applied to underperforming wells in order to enhance well performance and reduce production costs through the use of production treating chemicals, corrosion and scale monitoring, chemical inventory management, well failure analysis and lab services.

Service Lines

Our Oilfield Chemicals segment is divided into the following services lines:

Completion Chemicals.  Our completion chemicals service line develops, manufactures and provides a full suite of chemicals utilized in hydraulic fracturing, stimulation, cementing and well completions, including polymers that create viscosity, crosslinkers, friction reducers, surfactants, buffers, breakers and other chemical technologies, to leading pressure pumping service companies in the United States. Our product lines support the three major types of well completions (cross‑linked gel frac, linear fracs and slickwater fracs). We can provide 24/7/365 time‑critical logistical support to our customers. Our warehousing and service include inventory management with computerized tracking and monthly reporting. The use of automated communications systems combined with direct‑to‑wellsite delivery ensures seamless product availability for our customers, while our chemical expertise enables us to deliver a customized suite of products to meet customers’ technical and economical product needs. Our expertise in frac chemistry positions us to support our customers in the ever changing ways of how wells are completed with our wide range of manufactured products. We have two primary manufacturing facilities in Texas, five regional distribution centers and 29 heavy chemical transport trucks and provide products to our customers in all major U.S. shale basins.

Production Chemicals.  In our production chemicals service line, we analyze underperforming wells and design engineered chemical solutions to enhance production and well performance and reduce production costs. These chemical solutions include: production treating chemicals for use in oil and gas production; ancillary oilfield services including corrosion and scale monitoring, chemical inventory management and well failure analysis; and lab services. In the Permian, our centrally located lab provides complete water and bacteria analysis through the well life cycle beginning with frac water through the production cycle. Our strategy is to provide basin‑specific production chemicals solutions to operating companies that lower costs and increase production. Our solutions help customers avoid scaling and corrosion, hydrogen sulfide issues and paraffin build‑up. This service line differentiates our overall utility to operators by allowing us to manage the entire well life cycle. Our production chemicals service line complements our Water Solutions segment due to the pull‑through sales ability in the overlapping customer base, and it also complements our completion chemicals service line because we can advise customers on the completion fluid systems best suited for a well when it transitions from completion to production. We have two primary manufacturing facilities in Texas and one in Oklahoma. We serve the Permian, Eagle Ford and Mid‑Continent basins and offer analytical services, lab and field support through 23 field locations.

Specialty Chemicals.  Our specialty chemicals service line manufactures and distributes chemicals that are formulated specifically for the coiled tubing industry. We offer a complete line of fracturing, acid and coiled tubing products. We manufacture the emulsion polymers, xanthan gels and corrosion inhibitors that support the coil tubing operations.

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Geographic Areas of Operation

We provide Oilfield Chemicals services in most of the major unconventional shale plays in the continental U.S. In the chart below, a “” indicates that we offer the service line in the indicated geographic region.

 

 

 

 

 

 

 

 

 

 

Geographic Region

Services Provided

Permian

MidCon

Bakken

Eagle Ford

Marcellus /
Utica

Haynesville

Rockies

Completion Chemicals

Production Chemicals

Specialty Chemicals

 

Customers

Our Oilfield Chemicals customers primarily include oilfield services companies, including pressure pumpers, and major integrated and independent U.S. and international oil and gas producers.

Competition

Our Oilfield Chemical segment has a variety of different competitors, from companies that are pure distributors of commodities and specialty chemicals, to large manufacturers. What makes Rockwater unique is that we offer a distribution arm as well as the ability to manufacture in-basin. We believe that the principal competitive factors in the markets we serve are technical expertise, equipment capacity, work force competency, efficiency, safety record, reputation, experience and price. Additionally, projects are often awarded on a bid basis, which tends to create a highly competitive environment. We seek to differentiate ourselves from our competitors by delivering the highest‑quality services and equipment possible, coupled with superior execution and operating efficiency in a safe working environment.

Wellsite Services

Our Wellsite Services segment provides a number of services across the U.S. and Canada and is operated primarily under our subsidiaries Peak, Affirm and Rockwater LLC. Peak provides workforce accommodations and surface rental equipment supporting drilling, completion and production operations to the U.S. onshore oil and gas industry. Affirm provides oil and gas operators with a variety of services, including crane and logistics services, wellsite and pipeline construction and field services. Operating under Rockwater LLC, we also offer sand hauling and logistics services in the Rockies and Bakken regions as well as water transfer, containment, fluids hauling and other rental services in Western Canada.

Service Lines

Our Wellsite Services segment is divided into the following service lines:

Accommodations and Rentals.  Our accommodations and rentals service line, operating under our subsidiary, Peak, provides workforce accommodations and surface rental equipment supporting drilling, completion and production operations to support onshore oil and gas activity. The services provided include fully furnished office and living quarters, fresh water supply and wastewater removal, portable power generation and light plants, internet, phone, intercom, surveillance and monitoring services and other long‑term rentals supporting field personnel.

Wellsite Completion and Construction Services.  Our wellsite completion and construction services service line, operating under our subsidiary, Affirm, supports our Water Solutions segment and provides oil and gas operators and midstream companies with a variety of services, including crane and logistics services,

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wellsite and pipeline construction and field services. These services are performed to establish, maintain and improve production throughout the productive life of an oil or gas well, or to otherwise facilitate other services performed on a well.

Sand Hauling.  Our sand hauling service line, operating under our subsidiary, Rockwater LLC, provides proppant storage, transport, transloading, and sand and proppant supply and transportation logistics through our fleet of trucks.

Canada Fluids Logistics.  Our Canadian operations, operating under Rockwater Energy Solutions Canada, Inc., a subsidiary of Rockwater LLC, provide comprehensive fluids logistics through our fleet of tank trucks, vacuum trucks, hydro‑vac trucks, hot oilers, winch trucks and pressure trucks. Additionally, we provide water transfer, containment and other rental services throughout Western Canada.

Geographic Areas of Operation

We provide Wellsite Services in most of the major unconventional shale plays in the continental U.S. and in Western Canada. In the chart below, a “✓” indicates that we offer the service line in the indicated geographic region.

 

 

 

 

 

 

 

 

 

 

 

Geographic Region

Services Provided

Permian

MidCon

Bakken

Eagle Ford

Marcellus /
Utica

Haynesville

Rockies

Western
Canada

Accommodations & Rentals

Wellsite Completion & Construction Services

Sand Hauling

Canada Fluids Logistics

 

Customers

Our Wellsite Services customers include major integrated and independent U.S. and international oil and gas producers, as well as midstream and other oilfield services companies.

Competition

Historically, our competition has varied significantly by service line. The market for accommodations and rentals has been serviced by a relatively fragmented competitor base ranging from small local companies and privately‑owned regional service companies to large private and public companies operating across diverse geographies. Our main competitors in the market for wellsite completion and construction services are typically smaller or mid‑sized, and often private, service providers that focus on construction and field services across a narrow geographic range. Our competitors in the market for sand hauling are typically regionally focused smaller or mid‑sized service providers. Our primary competitors in our Canadian operations are regionally focused smaller or mid‑sized service providers. We seek to differentiate ourselves from our competitors by delivering the highest‑quality services and equipment possible, coupled with superior execution and operating efficiency in a safe working environment.

Significant Customer

There were no customers that accounted for 10.0% or more of our consolidated revenues for the years ended December 31, 2017 and 2016. For the year ended December 31, 2015, one of our customers accounted for approximately 10.6% of our total consolidated revenues.

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Sales and Marketing

Our sales activities are directed through a network of sales representatives and business development personnel, which provides us coverage at both the corporate and field level of our customers. Sales representatives work closely with local operations managers to target potential opportunities through strategic focus and planning. Customers are identified as targets based on their drilling and completion activity, geographic location, and economic viability. Direction of the sales team is conducted through multiple weekly meetings and daily reporting. Our sales strategy is also supported by a proprietary database that we have developed based upon current rig and permit activity and the location of our strategic water sources.

Our marketing activities are performed by an internal marketing group with input from a steering committee. Our strategy is based on building a national brand though multiple media outlets including our website, blog and social media accounts, radio, print and billboard advertisements, and various industry‑specific conferences, publications and lectures.

Engineered Water Solutions

Our Engineered Water Solutions group is comprised of professionals with significant technical and project development experience. The team consists of professionals with advanced degrees and experience in areas as diverse as geology, geography, petroleum and chemical engineering, computer science, environmental science, geographic information systems and regulatory affairs. This group has been designed to help customers develop and execute water solutions for wide‑scale development projects, with our professionals integrating themselves into our customers’ operations teams at the outset of the planning process.

Environmental and Occupational Safety and Health Matters

Our water‑related and wellsite completion and construction operations in support of oil and gas exploration, development and production activities pursued by our customers are subject to stringent and comprehensive federal, state, provincial and local laws and regulations in the United States and Western Canada governing occupational safety and health, the discharge of materials into the environment and environmental protection. Numerous governmental entities, including the U.S. Environmental Protection Agency (the “EPA”) and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them, often requiring difficult and costly actions. These laws and regulations may, among other things (i) require the acquisition of permits to take fresh water from surface water and groundwater, construct pipelines or containment facilities, drill wells and other regulated activities; (ii) restrict the types, quantities and concentration of various substances that can be released into the environment or injected into non‑producing formations; (iii) limit or prohibit our operations on certain lands lying within wilderness, wetlands and other protected areas; (iv) require remedial measures to mitigate pollution from former and ongoing operations; (v) impose specific safety and health criteria addressing worker protection; and (vi) impose substantial liabilities for pollution resulting from our operations. Any failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil and criminal penalties, the imposition of investigatory, remedial or corrective action obligations or the incurrence of capital expenditures; the occurrence of delays in the permitting or performance of projects; and the issuance of orders enjoining performance of some or all of our operations in a particular area.

The trend in United States and Canadian environmental regulation in recent years has been typically to place more restrictions and limitations on activities that may affect the environment, and thus any changes in environmental laws and regulations or re‑interpretation of enforcement policies that result in more stringent and costly construction, completion or water management activities, or waste handling, storage transport, disposal, or remediation requirements could have a material adverse effect on our financial position and results of operations. We may be unable to pass on such increased compliance costs to our customers. Moreover, accidental releases or spills may occur in the course of our operations, and we cannot assure you that we will not incur significant costs and liabilities as a result of such releases or spills, including any third‑party claims for damage to property, natural resources or persons. Our customers may also incur increased costs or delays or restrictions in permitting or operating activities as a result of more stringent

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environmental laws and regulations, which may result in a curtailment of exploration, development or production activities that would reduce the demand for our services.

United States Operations

The following is a summary of the more significant existing environmental and occupational safety and health laws, as amended from time to time, to which our operations in the United States are subject and for which compliance may have a material adverse impact on our capital expenditures, results of operations or financial position.

Hazardous substances and wastes.  The Resource Conservation and Recovery Act (“RCRA”), and comparable state statutes, regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non‑hazardous wastes. Pursuant to rules issued by the EPA, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Drilling fluids, produced waters, and most of the other wastes associated with the exploration, development, and production of oil or gas, if properly handled, are currently exempt from regulation as hazardous waste under RCRA, and instead are regulated under RCRA’s less stringent non‑hazardous waste provisions, state laws or other federal laws. However, it is possible that certain oil and gas drilling and production wastes now classified as non‑hazardous could be classified as hazardous wastes in the future. For example, following the filing of a lawsuit in the U.S. District Court for the District of Columbia in May 2016 by several non‑governmental environmental groups against the EPA for the agency’s failure to timely assess its RCRA Subtitle D criteria regulations for oil and gas wastes, the EPA and the environmental groups entered into an agreement that was finalized in a consent decree issued by the District Court in December 2016. Under the decree, the EPA is required to propose no later than March 15, 2019, a rulemaking for revision of certain Subtitle D criteria regulations pertaining to oil and gas wastes or sign a determination that revision of the regulations is not necessary. If the EPA proposes a rulemaking for revised oil and gas waste regulations, the Consent Decree requires that the EPA take final action following notice and comment rulemaking no later than July 15, 2021. A loss of the RCRA exclusion for drilling fluids, produced waters and related wastes could result in an increase in our and our oil and gas producing customers’ costs to manage and dispose of generated wastes, which could have a material adverse effect on our and our customers’ results of operations and financial position. In the course of our operations, we generate some amounts of ordinary industrial wastes, such as paint wastes, waste solvents and waste oils that may be regulated as hazardous wastes.

Wastes containing naturally occurring radioactive materials (“NORM”) may also be generated in connection with our operations. Certain processes used to produce oil and gas may enhance the radioactivity of NORM, which may be present in oilfield wastes. NORM is subject primarily to individual state radiation control regulations. In addition, NORM handling and management activities are governed by regulations promulgated by the Occupational Safety and Health Administration (“OSHA”). These state and OSHA regulations impose certain requirements concerning worker protection, the treatment, storage and disposal of NORM waste, the management of waste piles, containers and tanks containing NORM, as well as restrictions on the uses of land with NORM contamination.

The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as the Superfund law, and comparable state laws impose liability, without regard to fault or legality of conduct, on classes of persons considered to be responsible for the release of a “hazardous substance” into the environment. These persons include the current and past owner or operator of the site where the hazardous substance release occurred and anyone who disposed or arranged for the disposal of a hazardous substance released at the site. Under CERCLA, such persons may be subject to joint and several, strict liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. CERCLA also authorizes the EPA and, in some instances, third parties to act in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. In addition, neighboring landowners and other third parties may file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. We generate materials in the course of our operations that may be regulated as hazardous substances.

We currently own, lease, or operate numerous properties that have been used for activities supporting oil and gas exploration, development and production for a number of years. Although we believe that we have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes, or petroleum

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hydrocarbons may have been released on, under or from the properties owned or leased by us, or on, under or from other locations, including off‑site locations, where we conduct services for our customers or where such substances have been taken for treatment or disposal. In addition, some of our properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or petroleum hydrocarbons was not under our control. These properties and the substances disposed or released on, under or from them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to undertake response actions or corrective measures, which could include removal of previously disposed substances and wastes, cleanup of contaminated property or performance of remedial operations to prevent future contamination, the costs of which could be material.

Water discharges and use.  The Federal Water Pollution Control Act, also known as the Clean Water Act (“CWA”), and analogous state laws, impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and hazardous substances, into state waters and waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. Spill prevention, control and countermeasure plan requirements imposed under the CWA require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. In addition, the CWA and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities.

The CWA also prohibits the discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by permit. In June 2015, the EPA and the U.S. Army Corps of Engineers (the “Corps”) published a final rule attempting to clarify the federal jurisdictional reach over waters of the United States, but legal challenges to this rule followed, and the rule was stayed nationwide by the U.S. Sixth Circuit Court of Appeals in October 2015 pending resolution of the court challenges. In January 2017, the U.S. Supreme Court accepted review of the rule to determine whether jurisdiction rests with the federal district or appellate courts, and, in a decision issued on January 22, 2018, held that legal challenges of the rule must be heard at the district rather than appellate court level. Additionally, following the issuance of a presidential executive order to review the rule, the EPA and the Corps proposed a rulemaking in June 2017 to repeal the June 2015 rule. The EPA and the Corps also announced their intent to issue a new rule defining the CWA’s jurisdiction. On February 6, 2018, the EPA and Corps published a final rule specifying that the contested June 2015 rule would not take effect until February 6, 2020.  As a result, future implementation of the June 2015 rule is uncertain at this time. To the extent this rule or a revised rule expands the scope of the CWA’s jurisdiction, we could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas in connection with any expansion activities. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non‑compliance with discharge permits or other requirements of the CWA and analogous state laws and regulations.

The Oil Pollution Act of 1990 (“OPA”) amends the CWA and sets minimum standards for prevention, containment and cleanup of oil spills in waters of the United States. The OPA applies to vessels, offshore facilities, and onshore facilities, including E&P facilities that may affect waters of the United States. Under OPA, responsible parties including owners and operators of onshore facilities may be held strictly liable for oil cleanup costs and natural resource damages as well as a variety of public and private damages that may result from oil spills. The OPA also requires owners or operators of certain onshore facilities to prepare Facility Response Plans for responding to a worst‑case discharge of oil into waters of the United States.

Salt water disposal wells and induced seismicity.    Salt water disposal via underground injection is regulated pursuant to the Underground Injection Control (“UIC”) program established under the U.S. Safe Drinking Water Act (the “SDWA”) and analogous state and local laws and regulations. The UIC program includes requirements for permitting, testing, monitoring, record keeping and reporting of injection well activities, as well as a prohibition against the migration of fluid containing any contaminant into underground sources of drinking water. State regulations require a permit from the applicable regulatory agencies to operate underground injection wells. Although we monitor the injection process of our wells, any leakage from the subsurface portions of the injection wells could cause degradation of fresh groundwater resources, potentially resulting in suspension of our UIC permit, issuance of fines and penalties from governmental agencies, incurrence of expenditures for remediation of the affected resource and imposition of liability by

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third‑parties claiming damages for alternative water supplies, property and personal injuries. A change in UIC disposal well regulations or the inability to obtain permits for new disposal wells in the future may affect our ability to dispose of produced waters and other substances, which could affect our business.

Furthermore, in response to recent seismic events near underground disposal wells used for the disposal by injection of produced water resulting from oil and gas activities, federal and some state agencies are investigating whether such wells have caused increased seismic activity, and some states have restricted, suspended or shut down the use of such disposal wells. In response to these concerns, regulators in some states have imposed, or are considering imposing, additional requirements in the permitting of produced water disposal wells or otherwise to assess any relationship between seismicity and the use of such wells. For example, Oklahoma issued new rules for wastewater disposal wells in 2014 that imposed certain permitting and operating restrictions and reporting requirements on disposal wells in proximity to faults and also, from time to time, has developed and implemented plans directing certain wells where seismic incidents have occurred to restrict or suspend disposal well operations. The Texas Railroad Commission adopted similar rules in 2014. In December 2016, the Oklahoma Corporation Commission’s Oil and Gas Conservation Division and the Oklahoma Geological Survey released well completion seismicity guidance, which requires operators to take certain prescriptive actions, including an operator’s planned mitigation practices, following certain unusual seismic activity within 1.25 miles of hydraulic fracturing operations. In addition, the Oklahoma Corporation Commission’s Oil and Gas Conservation Division issued an order in February 2017 limiting future increases in the volume of oil and natural gas wastewater injected below ground into the Arbuckle formation in an effort to reduce the number of earthquakes in the state, and imposed further reductions in the Edmonds area of the state in August 2017. In addition, ongoing lawsuits allege that disposal well operations have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. The adoption and implementation of any new laws, regulations or directives that restrict our ability to dispose of wastewater gathered from our customers by limiting volumes, disposal rates, disposal well locations or otherwise, or requiring us to shut down disposal wells, could have a material adverse effect on our business, financial condition, and results of operations.

Hydraulic fracturing activities.    As noted, hydraulic fracturing involves the injection of water, sand or other proppants and chemical additives under pressure into targeted geological formations to fracture the surrounding rock and stimulate production. Hydraulic fracturing is currently generally exempt from regulation under the UIC program established under the SDWA. Hydraulic fracturing is regulated by state oil and gas commissions or similar agencies.

However, several federal agencies have asserted regulatory authority over certain aspects of the process. For example, in 2014, the EPA asserted regulatory authority pursuant to the SDWA’s UIC program over hydraulic fracturing activities involving the use of diesel and issued guidance covering such activities. Additionally, in June 2016, the EPA published an effluent limit guideline final rule prohibiting the discharge of wastewater from onshore unconventional oil and gas extraction facilities to publicly owned wastewater treatment plants and, in 2014, published an Advance Notice of Proposed Rulemaking regarding the Toxic Substances Control Act (“TSCA”) reporting of the chemical substances and mixtures used in hydraulic fracturing. Also, the Bureau of Land Management (“BLM”) published a final rule in 2015 that established new or more stringent standards relating to hydraulic fracturing on federal and American Indian lands. However, in June 2016, a Wyoming federal judge struck down this final rule, finding that the BLM lacked authority to promulgate the rule, the BLM appealed this decision to the U.S. Court of Appeals for the Tenth Circuit in July 2016, the appellate court issued a ruling in September 2017 to vacate the Wyoming trial court decision and dismiss the lawsuit challenging the 2015 rule in response to the BLM’s issuance of a proposed rulemaking to rescind the 2015 rule and, in December 2017, the BLM published a final rule rescinding the 2015 rule. In January 2018, litigation challenging the BLM’s recission of the 2015 rule was brought in federal court. In January 2018, litigation challenging the BLM’s recissionof the 2015 rule was brought in federal court.

From time to time, legislation has been introduced, but not enacted, in Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process. In the event that new federal restrictions on the hydraulic‑fracturing process are adopted in areas where we or our customers conduct business, we or our customers may incur additional costs or permitting requirements to comply with such federal requirements that may be significant in nature and our customers could experience added delays or curtailment in their exploration, development, or production activities, which would in turn reduce the demand for our services.

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Moreover, some states and local governments have adopted, and other governmental entities are considering adopting, regulations that could impose more stringent permitting, disclosure and well‑construction requirements on hydraulic fracturing operations, including states where we or our customers operate. For example, Texas, Oklahoma, California, Ohio, Pennsylvania and North Dakota, among others, have adopted regulations that impose new or more stringent permitting, disclosure, disposal and well‑construction requirements on hydraulic fracturing operations. States could also elect to prohibit high volume hydraulic fracturing altogether, following the approach taken by the State of New York. In addition to state laws, local land use restrictions, such as city ordinances, may restrict drilling in general and/or hydraulic fracturing in particular, as certain local governments in California have done. Other states, such as Texas, Oklahoma and Ohio have taken steps to limit the authority of local governments to regulate oil and gas development.

In December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources. The final report concluded that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources “under some circumstances,” noting that the following hydraulic fracturing water cycle activities and local‑ or regional‑scale factors are more likely than others to result in more frequent or more severe impacts: water withdrawals for fracturing in times or areas of low water availability; surface spills during the management of fracturing fluids, chemicals or produced water; injection of fracturing fluids into wells with inadequate mechanical integrity; injection of fracturing fluids directly into groundwater resources; discharge of inadequately treated fracturing wastewater to surface waters; and disposal or storage of fracturing wastewater in unlined pits. The EPA’s study report did not find a direct link between the action of hydraulically fracturing the well itself and contamination of groundwater resources. Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition to oil and gas production activities using hydraulic fracturing techniques. Additional legislation or regulation could also lead to operational delays or increased operating costs for our customers in the production of oil and gas, including from the developing shale plays, or could make it more difficult to perform hydraulic fracturing. The adoption of any federal, state or local laws or the implementation of regulations regarding hydraulic fracturing could potentially cause a decrease in the completion of new oil and gas wells and an associated decrease in demand for our services, increased compliance costs and time, which could have a material adverse effect on our liquidity, consolidated results of operations, and consolidated financial condition.

Air Emissions.  The U.S. Clean Air Act (“CAA”) and comparable state laws restrict the emission of air pollutants from many sources through air emissions standards, construction and operating permit programs and the imposition of other compliance standards. These laws and regulations may require us to obtain pre‑approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements or utilize specific equipment or technologies to control emissions of certain pollutants. The need to obtain permits has the potential to delay our projects as well as our customers’ development of oil and gas projects. Over the next several years, we or our customers may incur certain capital expenditures for air pollution control equipment or other air emissions‑related issues. For example, in 2015, the EPA issued a final rule under the CAA, lowering the National Ambient Air Quality Standard (“NAAQS”) for ground‑level ozone from the current standard of 75 parts per million to 70 parts per million under both the primary and secondary standards to provide requisite protection of public health and welfare, respectively. The EPA published a final rule on November 16, 2017 that issued area designations with respect to ground-level ozone for approximately 85% of the U.S. counties as either “attainment/unclassifiable” or “unclassifiable” that became effective on January 18, 2018, and is expected to issue attainment or non-attainment designations for the remaining areas of the U.S. not addressed in the November 2017 final rule in the first half of 2018. Reclassification of areas or imposition of more stringent standards may make it more difficult to construct new facilities or modify existing facilities in these newly designated non‑attainment areas. Also, states are expected to implement more stringent requirements as a result of this new final rule, which could apply to our and our customers’ operations. In another example, in June 2016, the EPA published a final rule updating federal permitting regulations for stationary sources in the oil and natural gas industry by defining and clarifying the meaning of the term “adjacent” for determining when separate surface sites and the equipment at those sites will be aggregated for permitting purposes. Compliance with these or other air pollution control and permitting requirements has the potential to delay the development of oil and natural gas projects and increase our or our customers’ costs of development and production, which costs could reduce demand for our services and have a material adverse impact on our business and results of operations.

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Climate Change.  In response to findings that emissions of carbon dioxide, methane and other greenhouse gases (“GHGs”) present an endangerment to public health and the environment, the EPA has adopted regulations under existing provisions of the CAA that, among other things, establish Prevention of Significant Deterioration (“PSD”) construction and Title V operating permit reviews for certain large stationary sources that emit certain principal, or “criteria,” pollutants. Facilities required to obtain PSD permits for their GHG emissions also will be required to meet “best available control technology” standards. In addition, the EPA has adopted rules requiring the monitoring and annual reporting of GHG emissions from oil and gas production, processing, transmission and storage facilities in the United States.

Congress has from time to time considered legislation to reduce emissions of GHGs but there has not been significant activity in the form of adopted legislation to reduce GHG emissions at the federal level in recent years. In the absence of such federal climate legislation, a number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions through the completion of GHG emissions inventories and by means of cap and trade programs that typically require major sources of GHG emissions to acquire and surrender emission allowances in return for emitting those GHGs. The EPA has also developed strategies for the reduction of methane emissions, including emissions from the oil and gas industry. For example, in June 2016, the EPA published New Source Performance Standards (“NSPS”) Subpart OOOOa requirements to reduce methane and volatile organic compound (“VOC”) emissions from certain new, modified and reconstructed equipment and processes in the oil and gas source category, including production, processing, transmission and storage activities. These Subpart OOOOa standards will expand previously issued NSPS published by the EPA in 2012, and known as Subpart OOOO, by using certain equipment‑specific emissions control practices. However, the Quad OOOOa standards have been subject to attempts by the EPA to stay portions of those standards, and the agency proposed rulemaking in June 2017 to stay the requirements for a period of two years and revisit implementation of Subpart OOOOa in its entirety. The EPA has not yet published a final rule, and, as a result of these developments, EPA’s 2016 standards are currently in effect, but future implementation of the 2016 standards is uncertain at this time. Because of the long‑term trend toward increasing regulation, however, future federal GHG regulations of the oil and natural gas industry remain a possibility. Furthermore, in June 2017, the BLM published a final rule that established, among other things, requirements to reduce methane emissions arising from venting, flaring and leakage from oil and gas production activities on onshore federal and American Indian lands. However, on December 8, 2017, the BLM published a final rule to temporarily suspend or delay certain requirements contained in the November 2016 final rule until January 17, 2019, including those requirements relating to venting, flaring and leakage from oil and gas production activities. On February 22, 2018, the U.S. District Court for the Northern District of California enjoined the delay of certain requirements contained in the November 2016 rule. As a result, the November 2016 rule, as originally proumulgated, is in effect. Also, on February 22, 2018, the BLM published a proposed rule that would generally re-establish the requirements that the November 2016 rule replaced. Litigation regarding the November 2016 rule is ongoing and uncertainty exists with respect to future implementation of the rule. However, given the long‑term trend towards increasing regulation, future federal GHG regulations of the oil and gas industry remain a possibility.

Additionally, in December 2015, the United States joined the international community at the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France that proposed an agreement, requiring member countries to review and “represent a progression” in their intended nationally determined contributions, which set GHG emission reduction goals every five years beginning in 2020. This agreement was signed by the United States in April 2016 and entered into force in November 2016; however, the GHG emission reductions called for by the Paris Agreement are not binding. In August 2017, the U.S. Department of State officially informed the United Nations of the intent of the United States to withdraw from the Paris Agreement. The Paris Agreement provides for a four‑year exit process beginning when it took effect in November 2016, which would result in an effective exit date of November 2020. The United States’ adherence to the exit process and/or the terms on which the United States may re‑enter the Paris Agreement or a separately negotiated agreement are unclear at this time.

Although it is not possible at this time to predict how new laws or regulations in the United States or any legal requirements imposed by the Paris Agreement on the United States, should it not withdraw from the agreement, that may be adopted or issued to address GHG emissions would impact our business, any such future laws, regulations or other legal requirements imposing reporting or permitting obligations on, or limiting emissions of GHGs from, our or our customers’ equipment and operations could require us or our customers to incur costs to reduce emissions of GHGs

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associated with operations as well as result in delays or restrictions in the ability to permit GHG emissions from new or modified sources. In addition, substantial limitations on GHG emissions could adversely affect demand for the oil and gas our customers produce, which could reduce demand for our services. Moreover, activists concerned about the potential effects of climate change have directed their attention at sources of funding for fossil-fuel energy companies, which has resulted in certain financial institutions, funds and other sources of capital restricting or eliminating their investment in oil and natural gas activities. Ultimately, this could make it more difficult to secure funding for exploration and production activities. Notwithstanding potential risks related to climate change, the International Energy Agency estimates that global energy demand will continue to rise and will not peak until after 2040 and that oil and gas will continue to represent a substantial percentage of global energy use over that time. Finally, it should be noted that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods, droughts and other climatic events. If any such effects were to occur, they could have an adverse effect on our and our customers’ operations.

Endangered Species.  The federal Endangered Species Act (the “ESA”) restricts activities that may affect endangered or threatened species or their habitats. Similar protections are offered to migratory birds under the federal Migratory Bird Treaty Act (the “MBTA”). To the extent species that are listed under the ESA or similar state laws, or are protected under the MBTA, live in the areas where we or our oil and gas producing customers operate, our and our customers’ abilities to conduct or expand operations and construct facilities could be limited or be forced to incur material additional costs. Moreover, our customers’ drilling activities may be delayed, restricted, or precluded in protected habitat areas or during certain seasons, such as breeding and nesting seasons. Some of our operations and the operations of our customers are located in areas that are designated as habitats for protected species. In addition, as a result of one or more settlements entered into by the U.S. Fish & Wildlife Service (the “FWS”), the agency is required to make a determination on the listing of numerous other species as endangered or threatened under the ESA pursuant to specific timelines. The designation of previously unidentified endangered or threatened species could indirectly cause us to incur additional costs, cause our or our oil and gas producing customers’ operations to become subject to operating restrictions or bans and limit future development activity in affected areas. The FWS and similar state agencies may designate critical or suitable habitat areas that they believe are necessary for the survival of threatened or endangered species. Such a designation could materially restrict use of or access to federal, state, and private lands.

Chemical Safety.  We are subject to a wide array of laws and regulations governing chemicals, including the regulation of chemical substances and inventories, such as TSCA in the United States and the Canadian Environmental Protection Act in Canada. These laws and regulations change frequently, and have the potential to limit or ban altogether the types of chemicals we may use in our products, as well as result in increased costs related to testing, storing, and transporting our products prior to providing them to our customers. For example, in June 2016, President Obama signed into law the Frank R. Lautenberg Chemical Safety for the 21st Century Act (the “Lautenberg Act”), which substantially revised TSCA. Amongst other items, the Lautenberg Act eliminated the cost‑benefit approach to analyzing chemical safety concerns with a health‑based safety standard and requires all chemicals in commerce, including those “grandfathered” under TSCA, to undergo a safety review. The Lautenberg Act also requires safety findings before a new chemical can enter the market. Although it is not possible at this time to predict how EPA will implement and interpret the new provisions of the Lautenberg Act, or how legislation or new regulations that may be adopted pursuant to these regulatory and legislative efforts would impact our business, any new restrictions on the development of new products, increases in regulation, or disclosure of confidential, competitive information could have an adverse effect on our operations and our cost of doing business.

Furthermore, governmental, regulatory and societal demands for increasing levels of product safety and environmental protection could result in increased pressure for more stringent regulatory control with respect to the chemical industry. In addition, these concerns could influence public perceptions regarding our products and operations, the viability of certain products, our reputation, the cost to comply with regulations, and the ability to attract and retain employees. Moreover, changes in environmental, health and safety regulations could inhibit or interrupt our operations, or require us to modify our facilities or operations. Accordingly, environmental or regulatory matters may cause us to incur significant unanticipated losses, costs or liabilities, which could reduce our profitability.

Occupational Safety and Health and other legal requirements.  We are subject to the requirements of the Federal Occupational Safety and Health Act and comparable state statutes whose purpose is to protect the health and safety of workers. In addition, the OSHA’s hazard communication standard, the EPA’s Emergency Planning and Community Right‑to‑Know Act and comparable state regulations and any implementing regulations require that we

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organize and/or disclose information about hazardous materials used or produced in our United States operations and that this information be provided to employees, state and local governmental authorities and citizens. We have an internal program of inspection designed to monitor and enforce compliance with worker safety requirements.

In addition, as part of the services we provide, we operate as a motor carrier and therefore are subject to regulation by the U.S. Department of Transportation (“U.S. DOT”) and analogous U.S. state agencies. These regulatory authorities exercise broad powers, governing activities such as the authorization to engage in motor carrier operations, regulatory safety, and hazardous materials labeling, placarding and marking. There are additional regulations specifically relating to the trucking industry, including testing and specification of equipment and product handling requirements. The trucking industry is subject to possible regulatory and legislative changes that may affect the economics of the industry by requiring changes in operating practices or by changing the demand for common or contract carrier services or the cost of providing truckload services. From time to time, various legislative proposals are introduced, including proposals to increase federal, state or local taxes on motor fuels, among other things, which may increase our costs or adversely impact the recruitment of drivers. We cannot predict whether, or in what form, any increase in such taxes applicable to us will be enacted.

Western Canadian Operations

Environmental regulation in Canada, including the Western Canadian provinces of Alberta and British Columbia, is carried out at both the federal and provincial levels. Unless the exploration and production of hydrocarbon resources is occurring on federal lands, such as lands held by First Nations, national parks, national defense lands or offshore, the main oversight over the extraction of natural resources falls within provincial jurisdiction. However, the federal government has shared oversight over assessing whether substances are toxic to both humans and the environment and the control of the use of such substances pursuant to the Canadian Environmental Protection Act. In addition, the Transportation of Dangerous Goods Act, administered by Transport Canada, regulates road, rail, air and marine transportation of fracturing fluids, produced water, fracturing fluid waste and flowback. The following is a summary of the more significant environmental regulations in Alberta and British Columbia, Canada, as amended from time to time, to which our operations in Canada are subject and for which compliance may have a material adverse impact on our capital expenditures, results of operations or financial position.

Hydraulic fracturing activities.  Operations related to water, stimulation, and fracturing fluids in support of oil and gas exploration, development and production are subject to provincial environmental regulations. Currently, our operations occur in the western provinces of Alberta and British Columbia. In Alberta, the Alberta Energy Regulator (“AER”) has jurisdiction over the Environmental Protection and Enhancement Act, and associated regulations and Directives, as well as parts of the Water Act, relating to the extraction of hydrocarbons. In particular, the AER has regulatory directives relating to groundwater protection, wellbore integrity, noise and light impacts, air quality and induced seismicity. The AER’s Directives require licensees conducting hydraulic fracturing to report amounts and sources of water and chemicals used in each job. The type and volume of all additives used in fracturing fluids must also be submitted to the AER. Licensees in Alberta are also subject to stringent storage and drilling waste management requirements. Companies who own and operate permanent facilities are subject to additional regulations.

In British Columbia, the British Columbia Oil and Gas Commission (the “BCOGC”) is the provincial regulatory body responsible for overseeing oil and gas operations. Like Alberta, British Columbia has developed a single‑window approach to administer the provisions of wide ranging acts and regulations which include the regulation of the exploration, development, transportation and reclamation of oil and gas activities. The regulation of hydraulic fracturing in British Columbia is conducted under numerous provincial acts and technical regulations. The BCOGC administers British Columbia’s main legislative framework relating to oil and gas, the Oil and Gas Activities Act, and its associated regulations which regulate public safety and environmental protection related to hydraulic fracturing, such as the Drilling and Production Regulation and the Environmental Protection and Management Regulation. Further, other specific provisions of the Water Act, the Petroleum and Natural Gas Act, the Heritage Conservation Act, the Land Act and the Environmental Management Act also regulate elements of hydraulic fracturing. Fracture Fluid Reports are required to be submitted and are publicly searchable online. Chemical disclosure including trade name, supplier, purpose, ingredients and volume of water with injected ingredients must be submitted to an online database.

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Water usage.  Besides the AER, the other major legislative and regulatory requirements in Alberta related to our operations in Western Canada fall under the administration of the Alberta Environment and Parks ministry. Environment and Parks oversees parts of the Water Act and the Water Conservation and Allocation Policy for Oilfield Injection for long‑term water injection projects for the recovery of oil, requiring industry to seek deep saline groundwater and technological alternatives to minimize use of fresh water. While this policy is applicable to conventional water flooding and oil sands in‑situ operations, expanding the policy to apply water conservation principles to subsectors of the upstream oil and gas industry, including hydraulic fracturing, has been proposed. In British Columbia, the Water Sustainability Act came into effect in 2016 and has resulted in changes to surface water and groundwater allocation, requiring authorizations to be obtained to use groundwater for anything other than domestic use. The BCOGC has recently strengthened regulations relating to induced seismicity due to hydraulic fracturing based on two reports and continues to conduct monitoring and research in order to adequately respond and mitigate this issue.

Induced seismicity.  Due to increased seismicity believed to be associated with hydraulic fracturing, in 2015 the AER released new guidelines requiring new seismic monitoring and reporting requirements for hydraulic fracturing. The BCOGC completed two reports on seismic events related to hydraulic fracturing, and has imposed mitigation measures, including regulations to shut down industry operations if seismic activity reaches a certain threshold.

Climate change.  The Canadian federal government, as well as the provincial governments have either proposed or have instituted a carbon tax in response to the global push to combat climate change. While a carbon tax in British Columbia has been in place since 2008, which is currently $30 per tonne of carbon dioxide equivalent, as of January 1, 2017, Alberta has instituted a provincial carbon tax of $20 per tonne, rising to $30 per tonne in 2018. The federal government has proposed a minimum price on carbon, beginning in 2018 at $10 per tonne, rising to $50 per tonne in 2022, which will be implemented by the federal government if the provinces do not already have an equivalent framework in place. The carbon tax will have a significant impact on energy intensive businesses.

The Government of Alberta also announced in 2015 that under its Climate Leadership Plan, the province will have zero emissions from coal‑fired electricity by 2030. As approximately 55% of Alberta’s electricity in being produced from coal‑fired generators, natural gas‑fired electricity is expected to increase significantly to fill this gap. Oil and gas producers will be required to reduce methane emissions associated with their facilities by 45% by 2025 and a cap of 100 megatonnes per year of carbon emissions from oil sands production has been imposed. The federal government also announced that it intends to virtually eliminate the use of coal‑fired electricity by 2030, which currently accounts for 11% of Canada’s electricity capacity.

Seasonality

Our results of operations have historically reflected seasonal tendencies, typically in the fourth quarter, relating to holiday seasons, inclement winter weather and the conclusion of our customers’ annual drilling and completions capital expenditure budgets during which we typically experience declines in our operating results. In a stable commodity price and operations environment, October has historically been our most active month, with notable declines in November and December for the reasons described above.

Intellectual Property

Protection of our products and processes is important to our businesses. We own numerous patents and, where appropriate, we file patent applications for new products and technologies. For example, we use our AquaView® technology to quantify volumes and flow rates to verify current and potential water availability and volumes when analyzing a new water source. We also currently own six U.S. patents relating to completions technology including borate cross‑linkers, slurry monitoring systems and others. We also have a robust program to seek patents on new developments. We are currently seeking patents on eight new technologies, including a water treatment process and a proprietary water analytics and automation tool, as well as creating fracturing fluids with produced water, evaporation methodologies, cross‑linker/breaker mechanisms and liquid distribution metering systems. We hold numerous patents and, while a presumption of validity exists with respect to issued U.S. patents, we cannot assure that any of our patents will not be challenged, invalidated, circumvented or rendered unenforceable. Furthermore, we cannot assure the issuance of any pending patent application, or that if patents do issue, that these patents will provide meaningful protection against competitors or against competitive technologies. Additionally, our competitors or other third parties may obtain patents that restrict or preclude our ability to lawfully produce or sell our products in a competitive manner.

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We also rely upon unpatented proprietary know‑how, continuing technological innovation and trade secrets to develop and maintain our competitive position. There can be no assurance, however, that confidentiality and other agreements into which we enter and have entered will not be breached, that these agreements will provide meaningful protection for our trade secrets or proprietary know‑how, or that adequate remedies will be available in the event of an unauthorized use or disclosure of such trade secrets and know‑how. In addition, there can be no assurance that others will not obtain knowledge of these trade secrets through independent development or other access by legal means.

We also own a number of trademarks, which we use in connection with our businesses. In addition to protections through federal registration, we also rely on state common law protections to protect our brand. There can be no assurance that the trademark registrations will provide meaningful protection against the use of similar trademarks by competitors, or that the value of our trademarks will not be diluted.

Because of the breadth and nature of our intellectual property rights and our business, we do not believe that any single intellectual property right (other than certain trademarks for which we intend to maintain the applicable registrations) is material to our business. Moreover, we do not believe that the termination of intellectual property rights expected to occur over the next several years, either individually or in the aggregate, will materially adversely affect our business, financial condition or results of operations.

Risk Management and Insurance

Our operations are subject to hazards inherent in the oil and gas industry, including accidents, blowouts, explosions, craterings, fires, oil spills and hazardous materials spills. These conditions can cause:

personal injury or loss of life;

damage to, or destruction of property, the environment and wildlife; and

the suspension of our or our customers’ operations.

In addition, claims for loss of oil and gas production and damage to formations can occur in the well services industry. If a serious accident were to occur at a location where our equipment and services are being used, it could result in us being named as a defendant in lawsuits asserting large claims.

Because our business involves the transportation of heavy equipment and materials, we may also experience traffic accidents which may result in spills, property damage and personal injury.

Despite our efforts to maintain high safety standards, from time to time, we have suffered accidents, and there is a risk that we will experience accidents in the future. In addition to the property and personal losses from these accidents, the frequency and severity of these incidents affect our operating costs and insurability, and our relationship with customers, employees and regulatory agencies. In particular, in recent years many of our large customers have placed an increased emphasis on the safety records of their service providers. Any significant increase in the frequency or severity of these incidents, or the general level of compensatory payments, could adversely affect the cost of, or our ability to obtain, workers’ compensation and other forms of insurance, and could have other material adverse effects on our financial condition and results of operations.

We maintain insurance coverage of types and amounts that we believe to be customary in the industry including workers’ compensation, employer’s liability, sudden & accidental pollution, umbrella, comprehensive commercial general liability, business automobile and property and equipment physical damage insurance. Our insurance coverage may be inadequate to cover our liabilities. In addition, we may not be able to maintain adequate insurance in the future at rates we consider reasonable and commercially justifiable or on terms as favorable as our current arrangements.

We enter into master service agreements (“MSAs”) with each of our customers. Our MSAs delineate our and our customer’s respective indemnification obligations with respect to the services we provide. Generally, under our

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MSAs, including those relating to our Water Solutions and Related Services,  Oilfield Chemical Product Sales, Accommodations and Rentals and Completion and Construction Services, we assume responsibility for pollution or contamination originating above the surface from our equipment or handling of the equipment of others. However, our customers assume responsibility for all other pollution or contamination that may occur during operations, including that which may result from seepage or any other uncontrolled flow of drilling fluids. The assumed responsibilities include the control, removal and clean‑up of any pollution or contamination. In such cases, we may be exposed to additional liability if we are grossly negligent or commit willful acts causing the pollution or contamination. Generally, our customers also agree to indemnify us against claims arising from the personal injury or death of the customers’ employees or those of the customers’ other contractors, in the case of our hydraulic fracturing operations, to the extent that such employees are injured by such operations, unless the loss is a result of our gross negligence or willful misconduct. Similarly, we generally agree to indemnify our customers for liabilities arising from personal injury to or death of any of our employees or employees of any of our subcontractors, unless resulting from the gross negligence or willful misconduct of our customer. The same principals apply to mutual indemnification for loss or destruction of customer‑owned property or equipment, except such indemnification is not limited in an instance of gross negligence or willful misconduct. Losses arising from catastrophic events, such as blowouts, are generally the responsibility of the customer. However, despite this general allocation of risk, we may be unsuccessful in enforcing contractual terms, incur an unforeseen liability that is not addressed by the scope of the contractual provisions or be required to enter into an MSA with terms that vary from our standard allocations of risk, as described above. Consequently, we may incur substantial losses that could materially and adversely affect our financial condition and results of operations.

Employees

As of December 31, 2017, we had approximately 5,100 employees and no unionized labor. We believe we have good relations with our employees.

Available Information

We file or furnish annual, quarterly and current reports and other documents with the SEC under the Exchange Act. The public may read and copy any materials we file with the SEC at the SEC’s Public Reference Room at 100 F Street, NE, Washington, D.C. 20549, on official business days during the hours of 10 a.m. to 3 p.m. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC also maintains an internet website at www.sec.gov that contains reports, proxy and information statements and other information regarding issuers, including us, that file electronically with the SEC.

 

We also make available free of charge through our website, www.selectenergyservices.com, electronic copies of certain documents that we file with the SEC, including our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. Information on our website is not a part of this Form 10-K.

 

ITEM 1A.           RISK FACTORS 

The following risks could affect our financial performance or could cause actual results to differ materially from estimates contained in our forward-looking statements. We may encounter risks in addition to those described below. Additional risks and uncertainties not currently known to us, or that we currently deem to be immaterial, may also impair or adversely affect our business, results of operation, financial condition and prospects.

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Risks Related to Our Business

Our business depends on capital spending by the oil and gas industry in the United States and Western Canada, and reductions in capital spending could have a material adverse effect on our liquidity, results of operations and financial condition.

Our business is directly affected by our customers’ capital spending to explore for, develop and produce oil and gas in the United States and Canada. The significant decline in oil and gas prices that began in the fourth quarter of 2014 caused a reduction in the exploration, development and production activities of most of our customers and their spending on our services in 2015 and 2016, as well as a reduction in the rates we charged and the utilization of our assets. In 2017, our clients modestly increased their spending as compared to 2016 levels, and we expect continued increases in 2018. However, if oil and gas prices again decline, our customers may cancel or curtail their spending on our services. Reduced discovery rates of new oil and gas reserves in our market areas as a result of decreased capital spending may also have a negative long‑term impact on our business, even in an environment of stronger oil and gas prices, to the extent the reduced number of wells for us to service more than offsets increasing completion activity and intensity. Any of these conditions or events could adversely affect our operating results. If a recovery does not materialize and our customers fail to increase their capital spending, it could have a material adverse effect on our liquidity, results of operations and financial condition.

Industry conditions are influenced by numerous factors over which we have no control, including:

the domestic and foreign economic conditions and supply of and demand for oil and gas;

the level of prices, and expectations about future prices, of oil and gas;

the level of global oil and gas exploration and production;

governmental regulations, including the policies of governments regarding the exploration for and production and development of their oil and gas reserves;

taxation and royalty charges;

political and economic conditions in oil and gas producing countries;

actions by the members of Organization of Petroleum Exporting Countries with respect to oil production levels and announcements of potential changes in such levels;

global weather conditions and natural disasters;

worldwide political, military and economic conditions;

the cost of producing and delivering oil and gas;

the discovery rates of new oil and gas reserves;

activities by non‑governmental organizations to limit certain sources of funding for the energy sector or restrict the exploration, development and production of oil and gas;

the ability of oil and gas producers to access capital;

technical advances affecting energy consumption; and

the potential acceleration of development of alternative fuels.

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If oil prices or gas prices were to decline, the demand for our services could be adversely affected.

The demand for our services is primarily determined by current and anticipated oil and gas prices and the related levels of capital spending and drilling activity in the areas in which we have operations. Volatility or weakness in oil prices or gas prices (or the perception that oil prices or gas prices will decrease) affects the spending patterns of our customers and may result in the drilling of fewer new wells or lower production spending on existing wells. This, in turn, could lead to lower demand for our services and may cause lower rates and lower utilization of our assets. If oil prices decline or gas prices decline, or if the recent increase in drilling activity reverses, the demand for our services and our results of operations could be materially and adversely affected.

Prices for oil and gas historically have been extremely volatile and are expected to continue to be volatile. During the past three years, the posted West Texas Intermediate (“WTI”) price for oil has ranged from a low of $26.19 per Bbl in February 2016 to a high of $107.95 per Bbl in June 2014. During 2017, WTI prices ranged from $42.48 to $60.46 per Bbl. If the prices of oil and gas reverse their recent increases or decline, our operations, financial condition, cash flows and level of expenditures may be materially and adversely affected.

We have developed certain key infrastructure assets in the Bakken area of North Dakota, making us vulnerable to risks associated with conducting business in this region.

We have secured three governmental permits that enable us to withdraw water from the Missouri River and Lake Sakakawea in North Dakota and have developed and expect to develop in the future significant water infrastructure related to these permits.

Because of the key nature of these permits and water infrastructure within the Bakken, the success and profitability of our business may be disproportionately exposed to factors impacting this region. These factors include, among others: (i) the prices of, and associated costs to produce, crude oil and gas from wells in the Bakken and other regional supply and demand factors (including the generally higher cost nature of production in the Bakken compared to other major shale plays and the pricing differentials that exist in the Bakken because of transportation constraints); (ii) the amount of exploration, development and production activities of our Bakken customers and their spending on our services; (iii) our ability to keep and maintain our governmental water permits; (iv) the cost of operations and the prices we can charge our customers in this region; and (v) the availability of equipment, supplies, and labor. Although we currently have secured key permits for water in this region, if we were to lose our water rights for any reason, including termination by the government upon the occurrence of a material breach, including nonpayment and default in performance, unexpected adverse environmental impacts, or our competitors were able to secure equivalent rights, our business could be materially harmed. In addition, our operations in the Bakken field may be adversely affected by severe weather events such as floods, blizzards, ice storms and tornadoes. For the years ended December 31, 2017, 2016 and 2015, our Bakken operations represented 10.4%, 9.6% and 5.5%, respectively, of our revenues. The concentration of our water permits and significant infrastructure assets in North Dakota also increases our exposure to changes in local laws and regulations, including those designed to protect wildlife, and unexpected events that may occur in this region such as seismic events, industrial accidents or labor difficulties. Any of the risks described above could have an adverse effect on our financial condition, results of operations and cash flows.

Restrictions on the ability to procure water or changes in water sourcing requirements could decrease the demand for our water‑related services.

Our business includes water transfer for use in our customers’ oil and gas E&P activities. Our access to the water we supply may be limited due to reasons such as prolonged drought or our inability to acquire or maintain water sourcing permits or other rights. In addition, some state and local governmental authorities have begun to monitor or restrict the use of water subject to their jurisdiction for hydraulic fracturing to ensure adequate local water supply. For instance, some states require E&P companies to report certain information regarding the water they use for hydraulic fracturing and to monitor the quality of groundwater surrounding some wells stimulated by hydraulic fracturing. In British Columbia, new regulations relating to the use of water under the Water Sustainability Act came into effect on February 29, 2016. This Act requires authorizations to be obtained to use groundwater for anything other than domestic use. The estimated 20,000 existing non‑domestic groundwater users must be brought into the licensing scheme. In

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addition, anyone who diverts water must make beneficial use of that water, meaning they must use the water as efficiently as practicable, and for the purposes specified by the license or approval. In Alberta, AER monitors water withdrawals, and may suspend water withdrawals during a low flow period or drought to protect the integrity of the water system. Further, in Alberta, the Water Conservation and Allocation Policy for Oilfield Injection may be expanded to include hydraulic fracturing activities under the proposed Water Conservation Policy for Upstream Oil and Gas Operations. If this policy is expanded to include hydraulic fracturing, licensees will come under increased scrutiny surrounding their water use. Groundwater and surface water available for licensing may be limited and in water‑short areas of Alberta, projects may be delayed until new technology or alternative water sources become available to protect non‑saline water resources. It is unclear if or when this policy may be implemented. Any such decrease in the availability of water, or demand for water services, could adversely affect our business and results of operations.

We have operated at a loss in the past, and there is no assurance of our profitability in the future.

Historically, we have experienced periods of low demand for our services and have incurred operating losses. In the future, we may not be able to reduce our costs, increase our revenues or reduce our debt service obligations sufficient to achieve or maintain profitability and generate positive operating income. Under such circumstances, we may incur further operating losses and experience negative operating cash flow.

Fuel conservation measures could reduce demand for oil and natural gas which would in turn reduce the demand for our services.

Fuel conservation measures, alternative fuel requirements and increasing consumer demand for alternatives to oil and natural gas could reduce demand for oil and natural gas. The impact of the changing demand for oil and natural gas may have a material adverse effect on our business, financial condition, prospects, results of operations and cash flows. Additionally, the increased competitiveness of alternative energy sources (such as wind, solar, geothermal, tidal, fuel cells and biofuels) could reduce demand for hydrocarbons and therefore for our services, which would lead to a reduction in our revenues.

Failure to successfully combine our business with the business from Rockwater may adversely affect our future results.

The consummation of the Rockwater Merger involves potential risks, including, without limitation, the failure to realize expected profitability, growth or accretion; the incurrence of liabilities or other compliance costs related to environmental or regulatory matters, including potential liabilities that may be imposed without regard to fault or the legality of conduct; diversion of management’s attention from our existing businesses; and the incurrence of unanticipated liabilities and costs for which indemnification is unavailable or inadequate. If these risks or other unanticipated liabilities were to materialize, any desired benefits of the Rockwater Merger may not be fully realized, if at all, and our future financial performance and results of operations could be negatively impacted.

The growth of our business through acquisitions may expose us to various risks, including those relating to difficulties in identifying suitable, accretive acquisition opportunities and integrating businesses, assets and personnel, as well as difficulties in obtaining financing for targeted acquisitions and the potential for increased leverage or debt service requirements.

As a component of our business strategy, we intend to pursue selected, accretive acquisitions of complementary assets, businesses and technologies. Acquisitions involve numerous risks, including:

unanticipated costs and assumption of liabilities and exposure to unforeseen liabilities of the acquired business, including but not limited to environmental liabilities;

difficulties in integrating the operations and assets of the acquired business and the acquired personnel;

limitations on our ability to properly assess and maintain an effective internal control environment over an acquired business;

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potential losses of key employees and customers of the acquired business;

risks of entering markets in which we have limited prior experience; and

increases in our expenses and working capital requirements.

In evaluating acquisitions, we generally prepare one or more financial cases based on a number of business, industry, economic, legal, regulatory and other assumptions applicable to the proposed transaction. Although we expect a reasonable basis will exist for those assumptions, the assumptions will generally involve current estimates of future conditions. Realization of many of the assumptions will be beyond our control. Moreover, the uncertainty and risk of inaccuracy associated with any financial projection will increase with the length of the forecasted period. Some acquisitions may not be accretive in the near term, and will be accretive in the long term only if we are able to timely and effectively integrate the underlying assets and such assets perform at or near the levels anticipated in our acquisition projections.

The process of integrating an acquired business may involve unforeseen costs and delays or other operational, technical and financial difficulties and may require a significant amount time and resources. Our failure to incorporate the acquired business and assets into our existing operations successfully or to minimize any unforeseen operational difficulties could have a material adverse effect on our financial condition and results of operations. Furthermore, there is intense competition for acquisition opportunities in our industry. Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions.

In addition, we may not have sufficient capital resources to complete any additional acquisitions. We may incur substantial indebtedness to finance future acquisitions and also may issue equity, debt or convertible securities in connection with such acquisitions. Debt service requirements could represent a significant burden on our results of operations and financial condition and the issuance of additional equity or convertible securities could be dilutive to our existing stockholders. Furthermore, we may not be able to obtain additional financing on satisfactory terms. Even if we have access to the necessary capital, we may be unable to continue to identify suitable acquisition opportunities, negotiate acceptable terms or successfully acquire identified targets.

Our Credit Agreement subjects us to various financial and other restrictive covenants. These restrictions may limit our operational or financial flexibility and could subject us to potential defaults under our Credit Agreement.

Our Credit Agreement subjects us to significant financial and other restrictive covenants, including restrictions on our ability to consolidate or merge with other companies, conduct asset sales, incur additional indebtedness, grant liens, issue guarantees, make investments, loans or advances, pay dividends and enter into certain transactions with affiliates.

Our Credit Agreement contains certain financial covenants, including the maintenance of a fixed charge coverage ratio of at least 1.0 to 1.0 at any time availability under the Credit Agreement is less than the greater of (i) 10% of the lesser of (A) the maximum revolver amount and (B) the then‑effective borrowing base and (ii) $15.0 million and continuing through and including the first day after such time that availability under the Credit Agreement has equaled or exceeded the greater of (i) 10% of the lesser of (A) the maximum revolver amount and (B) the then‑effective borrowing base and (ii) $15.0 million for 60 consecutive calendar days. Our ability to comply with such financial condition tests can be affected by events beyond our control and we may not be able to do so. Our scheduled maturity date is November 1, 2022. In addition, the Credit Agreement restricts SES Holdings’ and Select LLC’s ability to make distributions on, or redeem or repurchase, its equity interests, except for certain distributions, including distributions of cash so long as, both at the time of the distribution and after giving effect to the distribution, no default exists under the Credit Agreement and either (a) excess availability at all times during the preceding 30 consecutive days, on a pro forma basis and after giving effect to such distribution, is not less than the greater of (1) 25% of the lesser of (A) the maximum revolver amount and (B) the then‑effective borrowing base and (2) $37.5 million or (b) if SES Holdings’ fixed charge coverage ratio is at least 1.0 to 1.0 on a pro forma basis, and excess availability at all times during the preceding 30 consecutive days, on a pro forma basis and after giving effect to such distribution, is not less than the greater of (1) 20% of the lesser of (A) the maximum revolver amount and (B) the then‑effective borrowing base and (2) $30.0 million. For

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additional information regarding our Credit Agreement, please read “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Credit Agreement.”

If we are unable to remain in compliance with the covenants of our Credit Agreement, then the lenders may declare all amounts outstanding under the Credit Agreement to be immediately due and payable. Any such acceleration could have a material adverse effect on our financial condition and results of operations.

We may incur additional indebtedness or issue additional equity securities to execute our long‑term growth strategy, which may reduce our profitability or result in significant dilution to our stockholders.

Constructing and maintaining water infrastructure used in the oil and gas industry requires significant capital. We may require additional capital in the future to develop and construct water sourcing, transfer and other related infrastructure to execute our growth strategy. For the years ended December 31, 2017, 2016 and 2015, we incurred $108.3 million, $36.3 million and $48.7 million, respectively, in capital expenditures. Historically, we have financed these investments through cash flows from operations, our IPO, external borrowings and capital contributions from the existing owners of outstanding membership interests in SES Holdings prior to the Select 144A Offering and the related reorganization (the “Legacy Owners”) and certain of the Legacy Owners who received shares of our Class A common stock in exchange for their SES Holdings LLC Units received in connection with the corporate reorganization transactions related to the Select 144A Offering (the “Contributing Legacy Owners”). These sources of capital may not be available to us in the future. If we are unable to fund capital expenditures for any reason, we may not be able to capture available growth opportunities and any such failure could have a material adverse effect on our results of operations and financial condition. If we incur additional indebtedness or issue additional equity securities, our profitability may be reduced and our stockholders may experience significant dilution.

Significant price volatility or interruptions in supply of our raw materials may result in increased costs that we may be unable to pass on to our customers, which could reduce profitability.

We purchase a substantial portion of our raw materials from third‑party suppliers and the cost of these raw materials represents a substantial portion of our operating expenses. The prices of the raw materials that we purchase from third parties are cyclical and volatile. Our supply agreements provide us only limited protection against price volatility as they are entered into either on a short‑term basis or are longer‑term volume contracts, which provide for market‑based pricing renegotiated several times per year. While we attempt to match cost increases with corresponding product price increases, we are not always able to raise product prices immediately or at all. Timing differences between raw material prices, which may change daily, and contract product prices, which in many cases are negotiated only monthly or less often, have had and may continue to have a negative effect on our cash flow. Any cost increase that we are not able to pass on to our customers could have a material adverse effect on our business, results of operations, financial condition and liquidity.

There are several raw materials for which there are only a limited number of suppliers or a single supplier. To mitigate potential supply constraints, we enter into supply agreements with particular suppliers, evaluate alternative sources of supply and evaluate alternative technologies to avoid reliance on limited or sole‑source suppliers. Where supply relationships are concentrated, particular attention is paid by the parties to ensure strategic intentions are aligned to facilitate long‑term planning. If certain of our suppliers are unable to meet their obligations under present supply agreements, we may be forced to pay higher prices to obtain the necessary raw materials from other sources and we may not be able to increase prices for our finished products to recoup the higher raw materials costs. Any interruption in the supply of raw materials could increase our costs or decrease our revenue, which could reduce our cash flow. The inability of a supplier to meet our raw material needs could have a material adverse effect on our financial statements and results of operations.

The number of sources for and availability of certain raw materials is also specific to the particular geographical region in which a facility is located. Political and economic instability in the countries from which we purchase our raw material supplies could adversely affect their availability. In addition, if raw materials become unavailable within a geographic area from which they are now sourced, then we may not be able to obtain suitable or cost effective substitutes. We may also experience higher operating costs such as energy or transportation costs, which could affect our

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profitability. We may not always be able to increase our selling prices to offset the impact of any higher productions costs or reduced production levels, which could reduce our earnings and decrease our liquidity.

We may be subject to claims for personal injury and property damage, which could materially adversely affect our financial condition, results of operations and cash available for distribution.

We operate with most of our customers under MSAs. We endeavor to allocate potential liabilities and risks between the parties in the MSAs. Generally, under our MSAs, including those relating to our services, we assume responsibility for, including control and removal of, pollution or contamination which originates above surface and originates from our equipment or services. Our customer generally assumes responsibility for, including control and removal of, all other pollution or contamination which may occur during operations, including that which may result from seepage or any other uncontrolled flow of drilling fluids. We may have liability in such cases if we are negligent or commit willful acts. Generally, our customers also agree to indemnify us against claims arising from their employees’ personal injury or death to the extent that, in the case of our operations, their employees are injured or their properties are damaged by such operations, unless resulting from our gross negligence or willful misconduct. Similarly, we generally agree to indemnify our customers for liabilities arising from personal injury to or death of any of our employees, unless resulting from gross negligence or willful misconduct of the customer. In addition, our customers generally agree to indemnify us for loss or destruction of customer‑owned property or equipment and in turn, we agree to indemnify our customers for loss or destruction of property or equipment we own. Losses due to catastrophic events, such as blowouts, are generally the responsibility of the customer. However, despite this general allocation of risk, we might not succeed in enforcing such contractual allocation, might incur an unforeseen liability falling outside the scope of such allocation or may be required to enter into an MSA with terms that vary from the above allocations of risk. As a result, we may incur substantial losses which could materially and adversely affect our financial condition, results of operations and cash available for distribution.

We are subject to environmental and occupational health and safety laws and regulations that may expose us to significant liabilities for penalties, damages or costs of remediation or compliance.

Our operations and the operations of our customers are subject to federal, provincial, state and local laws and regulations in the United States and Western Canada relating to protection of natural resources and the environment, health and safety aspects of our operations and waste management, including the transportation and disposal of waste and other materials. These laws and regulations may impose numerous obligations on our operations and the operations of our customers, including the acquisition of permits to take fresh water from surface and underground sources, construct pipelines or containment facilities, drill wells or conduct other regulated activities, the incurrence of capital expenditures to mitigate or prevent releases of materials from our facilities or from customer locations where we are providing services, the imposition of substantial liabilities for pollution resulting from our operations, and the application of specific health and safety criteria addressing worker protection. Any failure on our part or the part of our customers to comply with these laws and regulations could result in restrictions on operations, assessment of administrative, civil and criminal penalties, revocation of permits and issuance of corrective action orders requiring the performance of investigatory, remedial or curative activities.

Our business activities present risks of incurring significant environmental costs and liabilities, including costs and liabilities resulting from our handling of oilfield and other wastes, because of air emissions and wastewater discharges related to our operations, and due to historical oilfield industry operations and waste disposal practices. Our businesses include the operation of oilfield waste disposal injection wells that pose risks of environmental liability, including leakage from the wells to surface or subsurface soils, surface water or groundwater. In addition, private parties, including the owners of properties upon which we perform services and facilities where our wastes are taken for reclamation or disposal, also may have the right to pursue legal actions to enforce compliance as well as to seek damages for non‑compliance with environmental laws and regulations or for personal injury or property or natural resource damages. Some environmental laws and regulations may impose strict liability, which means that in some situations we could be exposed to liability as a result of our conduct that was lawful at the time it occurred or the conduct of, or conditions caused by, prior operators or other third parties. Remedial costs and other damages arising as a result of environmental laws and costs associated with changes in environmental laws and regulations could be substantial and could have a material adverse effect on our liquidity, consolidated results of operations and consolidated financial condition.

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Laws and regulations protecting the environment generally have become more stringent in recent years and are expected to continue to do so, which could lead to material increases in costs for future environmental compliance and remediation. Changes in existing laws or regulations, or the adoption of new laws or regulations, could delay or curtail exploratory or developmental drilling for oil and gas and could limit well servicing opportunities. We may not be able to recover some or any of our costs of compliance with these laws and regulations from insurance.

Unsatisfactory safety performance may negatively affect our customer relationships and, to the extent we fail to retain existing customers or attract new customers, adversely impact our revenues.

Our ability to retain existing customers and attract new business is dependent on many factors, including our ability to demonstrate that we can reliably and safely operate our business and stay current on constantly changing rules, regulations, training and laws. Existing and potential customers consider the safety record of their service providers to be of high importance in their decision to engage third‑party servicers. If one or more accidents were to occur at one of our operating sites, the affected customer may seek to terminate or cancel its use of our facilities or services and may be less likely to continue to use our services, which could cause us to lose substantial revenues. Further, our ability to attract new customers may be impaired if they elect not to purchase our third‑party services because they view our safety record as unacceptable. In addition, it is possible that we will experience numerous or particularly severe accidents in the future, causing our safety record to deteriorate. This may be more likely as we continue to grow, if we experience high employee turnover or labor shortage, or add inexperienced personnel.

Federal, state, provincial and local legislative and regulatory initiatives in the United States and Western Canada related to hydraulic fracturing could result in operating restrictions or delays in the drilling and completion of oil and gas wells that may reduce demand for our services and could have a material adverse effect on our liquidity, consolidated results of operations and consolidated financial condition.

Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons from dense subsurface rock formations. The process involves the injection of water, sand or other proppants and chemical additives under pressure into targeted geological formations to fracture the surrounding rock and stimulate production. In the United States, hydraulic fracturing is currently generally exempt from regulation under the SDWA’s UIC program and is typically regulated by state oil and gas commissions or similar agencies.

However, several federal agencies in the United States have asserted regulatory authority over certain aspects of the process. For example, in 2014, the EPA asserted regulatory authority pursuant to the SDWA’s UIC program over hydraulic fracturing activities involving the use of diesel and issued guidance covering such activities. Additionally, in June 2016, the EPA published an effluent limit guideline final rule prohibiting the discharge of wastewater from onshore unconventional oil and gas extraction facilities to publicly owned wastewater treatment plants and, in 2014, issued a prepublication of its Advance Notice of Proposed Rulemaking regarding the TSCA reporting of the chemical substances and mixtures used in hydraulic fracturing. Also, the BLM published a final rule in 2015 that established new or more stringent standards relating to hydraulic fracturing on federal and American Indian lands. However, in June 2016, a Wyoming federal judge struck down this final rule, finding that the BLM lacked authority to promulgate the rule, the BLM appealed this decision to the U.S. Court of Appeals for the Tenth Circuit in July 2016, the appellate court issued a ruling in September 2017 to vacate the Wyoming trial court decision and dismiss the lawsuit challenging the 2015 rule in response to the BLM’s issuance of a proposed rulemaking to rescind the 2015 rule and, in December 2017, the BLM published a final rule rescinding the 2015 rule. In January 2018, litigation challenging the BLM’s recission of the 2015 rule was brought in federal court. In January 2018, litigation challenging the BLM’s recission of the 2015 rule was brought in federal court. From time to time, legislation has been introduced, but not enacted, in Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process. In the event that new federal restrictions on the hydraulic‑fracturing process are adopted in areas where we or our customers conduct business, we or our customers may incur additional costs or permitting requirements to comply with such federal requirements that may be significant in nature and, in the case of our customers, could experience added delays or curtailment in the pursuit of exploration, development, or production activities, which would in turn reduce the demand for our services.

Moreover, some states and local governments have adopted, and other governmental entities are considering adopting, regulations that could impose more stringent permitting, disclosure and well‑construction requirements on

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hydraulic fracturing operations, including states where we or our customers operate. For example, Texas, Oklahoma, California, Ohio, Pennsylvania and North Dakota, among others, have adopted regulations that impose new or more stringent permitting, disclosure, disposal and well construction requirements on hydraulic fracturing operations. States could also elect to prohibit high volume hydraulic fracturing altogether, following the approach taken by the State of New York. In addition, in light of concerns about seismic activity being triggered by the injection of produced waste waters into underground disposal wells, certain regulators are also considering additional requirements related to seismic safety for hydraulic fracturing activities. For example, the Oklahoma Corporation Commission released well completion seismicity guidelines in December 2016 for operators in the SCOOP and STACK that call for hydraulic fracturing operations to be suspended following earthquakes of certain magnitudes in the vicinity. In addition, the Oklahoma Corporation Commission’s Oil and Gas Conservation Division issued an order in February 2017 limiting future increases in the volume of oil and natural gas wastewater injected into the ground in an effort to reduce the number of earthquakes in the state, and imposed further reductions in the Edmonds area of the state in August 2017. In addition to state laws, local land use restrictions, such as city ordinances, may restrict drilling in general and/or hydraulic fracturing in particular, as certain local governments in California have done. Other states, such as Texas, Oklahoma and Ohio have taken steps to limit the authority of local governments to regulate oil and gas development.

In December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources. The final report concluded that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources “under some circumstances,” noting that the following hydraulic fracturing water cycle activities and local‑ or regional‑scale factors are more likely than others to result in more frequent or more severe impacts: water withdrawals for fracturing in times or areas of low water availability; surface spills during the management of fracturing fluids, chemicals or produced water; injection of fracturing fluids into wells with inadequate mechanical integrity; injection of fracturing fluids directly into groundwater resources; discharge of inadequately treated fracturing wastewater to surface waters; and disposal or storage of fracturing wastewater in unlined pits.

While hydraulic fracturing in Alberta and British Columbia, Canada has been occurring for decades, due to concerns over environmental impacts including water usage, wastewater disposal and contamination, and induced seismicity, the AER in Alberta and the BCOGC in British Columbia continue to conduct ongoing review of rules and regulations of the industry. The AER has moved to require water use measurement and sourcing details for all fractured wells in Alberta, fracture fluid chemical disclosure, limited trade secret protection and prescribed setbacks for shallow fracturing near water wells.

Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition to oil and gas production activities using hydraulic fracturing techniques. Additional legislation or regulation could also lead to operational delays or increased operating costs for our customers in the production of oil and gas, including from the developing shale plays, or could make it more difficult to perform hydraulic fracturing. The adoption of any federal, state or local laws or the implementation of regulations regarding hydraulic fracturing could potentially cause a decrease in the completion of new oil and gas wells and an associated decrease in demand for our services and increased compliance costs and time, which could have a material adverse effect on our liquidity, consolidated results of operations, and consolidated financial condition.

Climate change legislation or regulations in the United States and Western Canada restricting or regulating emissions of greenhouse gases could result in increased operating costs and reduced demand for our field services.

In the United States, in response to findings that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment, the EPA has adopted regulations under existing provisions of the CAA that, among other things, establish the PSD construction and Title V operating permit reviews for certain large stationary sources that emit certain principal, or “criteria,” pollutants. Facilities required to obtain PSD permits for their GHG emissions also will be required to meet “best available control technology” standards. In addition, the EPA has adopted rules requiring the monitoring and annual reporting of GHG emissions from oil and gas production, processing, transmission and storage facilities in the United States.

The U.S. Congress has from time to time considered legislation to reduce emissions of GHGs but there has not been significant activity in the form of adopted legislation to reduce GHG emissions at the federal level in recent years.

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In the absence of such federal climate legislation, a number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions through the completion of GHG emissions inventories and by means of cap and trade programs that typically require major sources of GHG emissions to acquire and surrender emission allowances in return for emitting those GHGs. The EPA has also developed strategies for the reduction of methane emissions, including emissions from the oil and gas industry. For example, in June 2016, the EPA published NSPS, known as Subpart OOOOa, that require certain new, modified or reconstructed facilities in the oil and natural gas sector to reduce methane gas and VOC emissions. These Subpart OOOOa standards will expand previously issued NSPS published by the EPA in 2012, and known as Subpart OOOO, by using certain equipment‑specific emissions control practices. However, the Quad OOOOa standards have been subject to attempts by the EPA to stay portions of those standards, and the agency proposed rulemaking in June 2017 to stay the requirements for a period of two years and revisit implementation of Subpart OOOOa in its entirety. The EPA has not yet published a final rule, and, as a result of these developments, EPA’s 2016 standards are currently in effect, but future implementation of the 2016 standards is uncertain at this time. Because of the long‑term trend toward increasing regulation, however, future federal GHG regulations of the oil and natural gas industry remain a possibility. Furthermore, in June 2017, the BLM published a final rule that established, among other things, requirements to reduce methane emissions arising from venting, flaring and leakage from oil and gas production activities on onshore federal and American Indian lands. However, on December 8, 2017, the BLM published a final rule to temporarily suspend or delay certain requirements contained in the November 2016 final rule until January 17, 2019, including those requirements relating to venting, flaring and leakage from oil and gas production activities. On February 22, 2018, the U.S. District Court for the Northern District of California enjoined the delay of certain requirements contained in the November 2016 rule. As a result, the November 2016 rule, as originally proumulgated, is in effect. Also, on February 22, 2018, the BLM published a proposed rule that would generally re-establish the requirements that the November 2016 rule replaced. Litigation regarding the November 2016 rule is ongoing and uncertainty exists with respect to future implementation of the rule. However, given the long‑term trend towards increasing regulation, future federal GHG regulations of the oil and gas industry remain a possibility. Furthermore, the EPA passed a new rule, known as the Clean Power Plan, to limit GHGs from power plants. While the U.S. Supreme Court issued a stay in February 2016, preventing implementation during the pendency of legal challenges to the rule in court, should the stay be lifted and legal challenges prove unsuccessful, then it could reduce demand for the oil and gas our customers produce, which could reduce the demand for our services, depending on the methods used to implement the rule. On October 10, 2017, the EPA issued a proposed rulemaking to repeal the Clean Power Plan. The public comment period on the proposed rulemaking ended on December 15, 2017.

Additionally, in December 2015, the United States joined the international community at the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France that proposed an agreement, requiring member countries to review and “represent a progression” in their intended nationally determined contributions, which set GHG emission reduction goals every five years beginning in 2020. This agreement was signed by the United States in April 2016 and entered into force in November 2016. This agreement does not create any binding obligations for nations to limit their GHG emissions, but rather includes pledges to voluntarily limit or reduce future emissions. In August 2017, the U.S. Department of State officially informed the United Nations of the intent of the United States to withdraw from the Paris Agreement. The Paris Agreement provides for a four‑year exit process beginning when it took effect in November 2016, which would result in an effective exit date of November 2020. The United States’ adherence to the exit process and/or the terms on which the United States may re‑enter the Paris Agreement or a separately negotiated agreement are unclear at this time.

In Canada, significant climate change initiatives are ongoing at both the provincial and federal levels. Prime Minister Justin Trudeau announced in late 2016 that provinces have until 2018 to impose a carbon pricing scheme or else a federally mandated price will be imposed. The price would be set at $10 per tonne of carbon dioxide in 2018, rising $10 each year, to $50 per tonne by 2022. The provincial government in Alberta, as of January 1, 2017, has implemented a carbon tax at a rate of $20 per tonne in 2017, rising to $30 per tonne in 2018. While British Columbia adopted a carbon tax in 2008, with the final scheduled increase occurring in 2012 at $30 per tonne, under the federal carbon tax, British Columbia’s carbon tax will be required to increase in 2021. In addition, Canada signed the Paris Agreement in April 2016, which could lead to additional regulation of GHG emissions.

Although it is not possible at this time to predict how new laws or regulations in the United States or Canada or any legal requirements imposed by the Paris Agreement on the United States, should it not withdraw from the

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agreement, or Canada that may be adopted or issued to address GHG emissions would impact our business, any such future laws, regulations or other legal requirements imposing reporting or permitting obligations on, or limiting emissions of GHGs from, our or our customers’ equipment and operations could require us or our customers to incur costs to reduce emissions of GHGs associated with operations as well as delays or restrictions in the ability to permit GHG emissions from new or modified sources. In addition, substantial limitations on GHG emissions could adversely affect demand for the oil and gas our customers produce, which could reduce demand for our services. Moreover, activists concerned about the potential effects of climate change have directed their attention at sources of funding for fossil-fuel energy companies, which has resulted in certain financial institutions, funds and other sources of capital restricting or eliminating their investment in oil and natural gas activities. Ultimately, this could make it more difficult to secure funding for exploration and production activities. Notwithstanding potential risks related to climate change, the International Energy Agency estimates that global energy demand will continue to rise and will not peak until after 2040 and that oil and gas will continue to represent a substantial percentage of global energy use over that time.

Finally, it should be noted that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods, droughts and other climatic events. If any such effects were to occur, they could have an adverse effect on our and our customers’ operations.

Legislation or regulatory initiatives intended to address seismic activity associated with oilfield disposal wells could restrict our ability to dispose of produced water gathered from our customers and, accordingly, could have a material adverse effect on our business.

We dispose of wastewater gathered from oil and gas producing customers that results from their drilling and production operations pursuant to permits issued to us by government authorities overseeing such disposal activities. While these permits are issued pursuant to existing laws and regulations, these legal requirements are subject to change, which could result in the imposition of more stringent permitting or operating constraints or new monitoring and reporting requirements owing to, among other things, concerns of the public or governmental authorities regarding such disposal activities.

One such concern relates to recent seismic events in the United States near underground disposal wells used for the disposal by injection of produced water resulting from oil and gas activities. Developing research suggests that the link between seismic activity and wastewater disposal may vary by region, and that only a very small fraction of the tens of thousands of injection wells have been suspected to be, or have been, the likely cause of induced seismicity. In March 2016, the United States Geological Survey identified six states with the most significant hazards from induced seismicity, including Oklahoma, Kansas, Texas, Colorado, New Mexico and Arkansas. The United States Geological Survey also noted the potential for induced seismicity in Ohio and Alabama. In response to concerns regarding induced seismicity, regulators in some states have imposed, or are considering imposing, additional requirements in the permitting of produced water disposal wells or otherwise to assess any relationship between seismicity and the use of such wells. For example, Oklahoma issued new rules for wastewater disposal wells in 2014 that imposed certain permitting and operating restrictions and reporting requirements on disposal wells in proximity to faults and also, from time to time, has developed and implemented plans directing certain wells where seismic incidents have occurred to restrict or suspend disposal well operations. In particular, the Oklahoma Corporation Commission released well completion seismicity guidelines in December 2016 for operators in the SCOOP and STACK that call for hydraulic fracturing operations to be suspended following earthquakes of certain magnitudes in the vicinity. In addition, the Oklahoma Corporation Commission’s Oil and Gas Conservation Division issued an order in February 2017 limiting future increases in the volume of oil and natural gas wastewater injected into the ground in an effort to reduce the number of earthquakes in the state and imposed further reductions in the Edmonds area of the state in August 2017. The Texas Railroad Commission adopted similar rules in 2014. In addition, ongoing lawsuits allege that disposal well operations have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. These developments could result in additional regulation and restrictions on the use of injection wells. Increased regulation and attention given to induced seismicity could lead to greater opposition to oil and gas activities utilizing injection wells for waste disposal. The adoption and implementation of any new laws, regulations or directives that restrict our ability to dispose of wastewater gathered from our customers by limiting, volumes, disposal rates, disposal well locations or otherwise, or requiring us to shut down disposal wells, could have a material adverse effect on our business, financial condition and results of operations.

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The Endangered Species Act and Migratory Bird Treaty Act in the United States and similar legislation applicable in Western Canada govern both our and our oil and gas producing customers’ operations and additional restrictions may be imposed in the future, which constraints could have an adverse impact on our ability to expand some of our existing operations or limit our customers’ ability to develop new oil and gas wells.

In the United States, the ESA restricts activities that may affect endangered or threatened species or their habitats. Similar protections are offered to migratory birds under the MBTA. To the extent species that are listed under the ESA or similar state laws, or are protected under the MBTA, live in the areas where we or our oil and gas producing customers’ operate, both our and our customers’ abilities to conduct or expand operations and construct facilities could be limited or be forced to incur material additional costs. Moreover, our customers’ drilling activities may be delayed, restricted or precluded in protected habitat areas or during certain seasons, such as breeding and nesting seasons. Some of our operations and the operations of our customers are located in areas that are designated as habitats for protected species.

In addition, as a result of one or more settlements approved by the FWS, the agency is required to make a determination on the listing of numerous other species as endangered or threatened under the ESA by the end of the FWS’ 2017 fiscal year. The designation of previously unidentified endangered or threatened species could indirectly cause us to incur additional costs, cause our or our oil and gas producing customers’ operations to become subject to operating restrictions or bans, and limit future development activity in affected areas. The FWS and similar state agencies may designate critical or suitable habitat areas that they believe are necessary for the survival of threatened or endangered species. Such a designation could materially restrict use of or access to federal, state and private lands.

In Canada, the Migratory Birds Convention Act (“MBCA”) prohibits the release of substances that can harm migratory birds in waters used by them, and gives the federal government the authority to develop regulations to protect migratory birds, and their habitats, including nests. Oil and gas development projects must comply with provisions of the MBCA, as well as the federal Species at Risk Act. Alberta and British Columbia each have a provincial Wildlife Act, which impose restrictions to prevent wildlife species from disappearing that could impact oil and gas operations and reduce demand for our services.

Our chemical products are subject to stringent chemical control laws that could result in increased costs on our business.

We are subject to a wide array of laws and regulations governing chemicals, including the regulation of chemical substances and inventories, such as the TSCA in the United States and the Canadian Environmental Protection Act in Canada. These laws and regulations change frequently, and have the potential to limit or ban altogether the types of chemicals we may use in our products, as well as result in increased costs related to testing, storing, and transporting our products prior to providing them to our customers. For example, in June 2016, President Obama signed into law the Lautenberg Act, which substantially revised TSCA. Among other items, the Lautenberg Act eliminated the cost‑benefit approach to analyzing chemical safety concerns with a health‑based safety standard and requires all chemicals in commerce, including those “grandfathered” under TSCA, to undergo a safety review. The Lautenberg Act also requires safety findings before a new chemical can enter the market. Although it is not possible at this time to predict how EPA will implement and interpret the new provisions of the Lautenberg Act, or how legislation or new regulations that may be adopted pursuant to these regulatory and legislative efforts would impact our business, any new restrictions on the development of new products, increases in regulation, or disclosure of confidential, competitive information could have an adverse effect on our operations and our cost of doing business.

Furthermore, governmental, regulatory and societal demands for increasing levels of product safety and environmental protection could result in increased pressure for more stringent regulatory control with respect to the chemical industry. In addition, these concerns could influence public perceptions regarding our products and operations, the viability of certain products, our reputation, the cost to comply with regulations, and the ability to attract and retain employees. Moreover, changes in environmental, health and safety regulations could inhibit or interrupt our operations, or require us to modify our facilities or operations. Accordingly, environmental or regulatory matters may cause us to incur significant unanticipated losses, costs or liabilities, which could reduce our profitability.

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Disruptions in production at our chemical manufacturing facilities may have a material adverse impact on our business, results of operations and/or financial condition.

Chemical manufacturing facilities in our industry are subject to outages and other disruptions. Any serious disruption at any of our facilities could impair our ability to use our facilities and have a material adverse impact on our revenue and increase our costs and expenses. Alternative facilities with sufficient capacity may not be available, may cost substantially more or may take a significant time to increase production or qualify with our customers, any of which could negatively impact our business, results of operations and/or financial condition. Long‑term production disruptions may cause our customers to seek alternative supply which could further adversely affect our profitability.

Unplanned production disruptions may occur for external reasons including natural disasters, weather, disease, strikes, transportation interruption, government regulation, political unrest or terrorism, or internal reasons, such as fire, unplanned maintenance or other manufacturing problems. Any such production disruption could have a material impact on our operations, operating results and financial condition.

In addition, we rely on a number of vendors, suppliers, and in some cases sole‑source suppliers, service providers, toll manufacturers and collaborations with other industry participants to provide us with chemicals, feedstocks and other raw materials, along with energy sources and, in certain cases, facilities that we need to operate our business. If the business of these third parties is disrupted, some of these companies could be forced to reduce their output, shut down their operations or file for bankruptcy protection. If this were to occur, it could adversely affect their ability to provide us with the raw materials, energy sources or facilities that we need, which could materially disrupt our operations, including the production of certain of our chemical products. Moreover, it could be difficult to find replacements for certain of our business partners without incurring significant delays or cost increases. All of these risks could have a material adverse effect on our business, results of operations, financial condition and liquidity.

While we maintain business recovery plans that are intended to allow us to recover from natural disasters or other events that could disrupt our business, we cannot provide assurances that our plans would fully protect us from the effects of all such disasters or from events that might increase in frequency or intensity due to climate change. In addition, insurance may not adequately compensate us for any losses incurred as a result of natural or other disasters. In areas prone to frequent natural or other disasters, insurance may become increasingly expensive or not available at all.

We operate in a highly competitive industry, which may intensify as our competitors expand their operations that may cause us to lose market share and could negatively affect our ability to expand our operations.

The water solutions business is highly competitive and includes numerous small companies capable of competing effectively in our markets on a local basis. Some of our competitors have a similarly broad geographic scope, as well as greater financial and other resources than we do, while others focus on specific basins only and may have local competitive cost efficiencies as a result. Additionally, there may be new companies that enter the water solutions business or our existing and potential customers may develop their own water solutions businesses. Our ability to maintain current revenue and cash flows, and our ability to expand our operations, could be adversely affected by the activities of our competitors and our customers. If our competitors substantially increase the resources they devote to the development and marketing of competitive services or substantially decrease the prices at which they offer their services, we may be unable to effectively compete. If our existing and potential customers develop their own water solutions businesses, we may not be able to effectively replace that revenue. All of these competitive pressures could have a material adverse effect on our business, results of operations and financial condition.

The oil and gas industry is intensely competitive, and we compete with other companies that have greater resources than us. Many of our larger competitors provide a broader base of services on a regional, national or worldwide basis. These companies may have a greater ability to continue oilfield service activities during periods of low commodity prices, to contract for equipment, to secure trained personnel, to secure contracts and permits and to absorb the burden of present and future federal, state, provincial, local and other laws and regulations (as applicable). Any inability to compete effectively with larger companies could have a material adverse impact on our financial condition and results of operations.

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We may be unable to implement price increases or maintain existing prices on our core services.

We periodically seek to increase the prices on our services to offset rising costs and to generate higher returns for our stockholders. However, we operate in a very competitive industry and as a result, we are not always successful in raising, or maintaining, our existing prices. Additionally, during periods of increased market demand, a significant amount of new service capacity, including new well service rigs, fluid hauling trucks and coiled tubing units, may enter the market, which also puts pressure on the pricing of our services and limits our ability to increase prices.

Even when we are able to increase our prices, we may not be able to do so at a rate that is sufficient to offset such rising costs. In periods of high demand for oilfield services, a tighter labor market may result in higher labor costs. During such periods, our labor costs could increase at a greater rate than our ability to raise prices for our services. Also, we may not be able to successfully increase prices without adversely affecting our activity levels. The inability to maintain our pricing and to increase our pricing as costs increase could have a material adverse effect on our business, financial position and results of operations.

Our operations involve risks that may increase our operating costs, which could reduce our profitability.

Although we take precautions to enhance the safety of our operations and minimize the risk of disruptions, our operations are subject to hazards inherent in the manufacturing and marketing of chemical and other products. These hazards include: chemical spills, pipeline leaks and ruptures, storage tank leaks, discharges or releases of toxic or hazardous substances or gases and other hazards incident to the manufacturing, processing, handling, transportation and storage of hazardous chemicals. We are also potentially subject to other hazards, including natural disasters and severe weather; explosions and fires; transportation problems, including interruptions, spills and leaks; mechanical failures; unscheduled downtimes; labor difficulties; remediation complications; and other risks. Many potential hazards can cause bodily injury and loss of life, severe damage to or destruction of property and equipment and environmental damage, and may result in suspension of operations and the imposition of civil or criminal penalties and liabilities. Furthermore, we are subject to present and future claims with respect to workplace exposure, exposure of contractors on our premises as well as other persons located nearby, workers’ compensation and other matters.

We maintain property, business interruption, products liability and casualty insurance policies which we believe are in accordance with customary industry practices, as well as insurance policies covering other types of risks, including pollution legal liability insurance, but we are not fully insured against all potential hazards and risks incident to our business. Each of these insurance policies is subject to customary exclusions, deductibles and coverage limits, in accordance with industry standards and practices. As a result of market conditions, premiums and deductibles for certain insurance policies can increase substantially and, in some instances, certain insurance may become unavailable or available only for reduced amounts of coverage. If we were to incur a significant liability for which we were not fully insured, it could have a material adverse effect on our business, results of operations, financial condition and liquidity.

In addition, we are subject to various claims and litigation in the ordinary course of business. We are a party to various pending lawsuits and proceedings. For more information, see “Item 3. Legal Proceedings.”

Our success depends on key members of our management, the loss of any of whom could disrupt our business operations.

We depend to a large extent on the services of some of our executive officers. The loss of the services of one or more of our key executives could increase our exposure to the other risks described in this “Risk Factors” section. We do not maintain key man insurance on any of our personnel other than John D. Schmitz, our Executive Chairman.

Our industry has experienced a high rate of employee turnover. Any difficulty we experience replacing or adding personnel could have a material adverse effect on our liquidity, results of operations and financial condition.

We are dependent upon the available labor pool of skilled employees and may not be able to find enough skilled labor to meet our needs, which could have a negative effect on our growth. We are also subject to the Fair Labor Standards Act, which governs such matters as minimum wage, overtime and other working conditions. Our services

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require skilled workers who can perform physically demanding work. As a result of our industry volatility, including the recent and pronounced decline in drilling activity, as well as the demanding nature of the work, many workers have left the oilfield services section to pursue employment in different fields. If we are unable to retain or meet growing demand for skilled technical personnel, our operating results and our ability to execute our growth strategies may be adversely affected.

Delays or restrictions in obtaining permits by us for our operations or by our customers for their operations could impair our business.

In most states, our operations and the operations of our oil and gas producing customers require permits from one or more governmental agencies in order to perform drilling and completion activities, secure water rights, construct impoundments tanks and operate pipelines or trucking services. In the United States, such permits are typically issued by state agencies, but federal and local governmental permits may also be required. Similarly, in Canada, permits are generally issued by provincial agencies. However, federal permits are required for certain activities, such as where a project occurs on lands under federal jurisdiction. Where projects occur on unoccupied Crown lands, treaty lands or in proximity to Reserves, project proponents may face significant delays due to challenges from First Nations people because First Nations have constitutionally guaranteed rights to hunt, trap and fish. Project proponents must conduct adequate consultation with affected First Nations, and projects may encounter lengthy delays if court challenges are made in regards to inadequate consultation. The requirements for such permits vary depending on the location where such drilling and completion, and pipeline and gathering, activities will be conducted. As with all governmental permitting processes, there is a degree of uncertainty as to whether a permit will be granted, the time it will take for a permit to be issued, the conditions that may be imposed in connection with the granting of the permit and whether the permit may be terminated. In addition, some of our customers’ drilling and completion activities may take place on federal land or Native American lands, requiring leases and other approvals from the federal government or Native American tribes to conduct such drilling and completion activities. Under certain circumstances, federal agencies may cancel proposed leases for federal lands and refuse to grant or delay required approvals. Therefore, our customers’ operations in certain areas of the United States may be interrupted or suspended for varying lengths of time, causing a loss of revenue to us and adversely affecting our results of operations in support of those customers.

In the future we may face increased obligations relating to the closing of our wastewater disposal facilities and may be required to provide an increased level of financial assurance to guarantee that the appropriate closure activities will occur for a wastewater disposal facility.

Obtaining a permit to own or operate wastewater disposal facilities generally requires us to establish performance bonds, letters of credit or other forms of financial assurance to address remediation and closure obligations. As we acquire additional wastewater disposal facilities or expand our existing wastewater disposal facilities, these obligations will increase. Additionally, in the future, regulatory agencies may require us to increase the amount of our closure bonds at existing wastewater disposal facilities. Moreover, actual costs could exceed our current expectations, as a result of, among other things, federal, state or local government regulatory action, increased costs charged by service providers that assist in closing wastewater disposal facilities and additional environmental remediation requirements. Increased regulatory requirements regarding our existing or future wastewater disposal facilities, including the requirement to pay increased closure and post‑closure costs or to establish increased financial assurance for such activities could substantially increase our operating costs and cause our available cash that we have to distribute to our unitholders to decline.

Constraints in the supply of equipment used in providing services to our customers and replacement parts for such could affect our ability to execute our growth strategies.

Equipment used in providing services to our customers is normally readily available. Market conditions could trigger constraints in the supply chain of certain equipment or replacement parts for such equipment, which could have a material adverse effect on our business. The majority of our risk associated with supply chain constraints occurs in those situations where we have a relationship with a single supplier for a particular resource.

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If we are unable to fully protect our intellectual property rights, we may suffer a loss in our competitive advantage or market share.

We do not have patents or patent applications relating to many of our proprietary chemicals. If we are not able to maintain the confidentiality of our trade secrets, or if our competitors are able to replicate our technology or services, our competitive advantage would be diminished. We also cannot assure you that any patents we may obtain in the future would provide us with any significant commercial benefit or would allow us to prevent our competitors from employing comparable technologies or processes.

Technology advancements in well service technologies, including those involving recycling of saltwater or the replacement of water in fracturing fluid, could have a material adverse effect on our business, financial condition and results of operations.

The oilfield services industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. The saltwater disposal industry is subject to the introduction of new waste treatment and disposal techniques and services using new technologies including those involving recycling of saltwater, some of which may be subject to patent protection. As competitors and others use or develop new technologies or technologies comparable to ours in the future, we may lose market share or be placed at a competitive disadvantage. For example, some oil and gas producers are focusing on developing and utilizing non‑water fracturing techniques, including those utilizing propane, carbon dioxide or nitrogen instead of water. Further, we may face competitive pressure to implement or acquire certain new technologies at a substantial cost. Some of our competitors may have greater financial, technical and personnel resources than we do, which may allow them to gain technological advantages or implement new technologies before we can. Additionally, we may be unable to implement new technologies or products at all, on a timely basis or at an acceptable cost. New technology could also make it easier for our customers to vertically integrate their operations or reduce the amount of waste produced in oil and gas drilling and production activities, thereby reducing or eliminating the need for third‑party disposal. Limits on our ability to effectively use or implement new technologies may have a material adverse effect on our business, financial condition and results of operations.

We may be adversely affected by uncertainty in the global financial markets and a worldwide economic downturn.

Our future results may be impacted by uncertainty caused by a worldwide economic downturn, continued volatility or deterioration in the debt and equity capital markets, inflation, deflation or other adverse economic conditions that may negatively affect us or parties with whom we do business resulting in a reduction in our customers’ spending and their non‑payment or inability to perform obligations owed to us, such as the failure of customers to honor their commitments or the failure of major suppliers to complete orders. Additionally, credit market conditions may change slowing our collection efforts as customers may experience increased difficulty in obtaining requisite financing, potentially leading to lost revenue and higher than normal accounts receivable. In the event of the financial distress or bankruptcy of a customer, we could lose all or a portion of such outstanding accounts receivable associated with that customer. Further, if a customer was to enter into bankruptcy, it could also result in the cancellation of all or a portion of our service contracts with such customer at significant expense to us.

The current global economic environment may adversely impact our ability to issue debt. Any economic uncertainty may cause institutional investors to respond to their borrowers by increasing interest rates, enacting tighter lending standards or refusing to refinance existing debt upon its maturity or on terms similar to the expiring debt. However, due to the above listed factors, we cannot be certain that additional funding will be available if needed and, to the extent required, on acceptable terms.

Our operations are subject to inherent risks, some of which are beyond our control. These risks may be self‑insured, or may not be fully covered under our insurance policies.

Our operations are subject to hazards inherent in the oil and gas industry, such as, but not limited to, accidents, blowouts, explosions, craterings, fires, oil spills and releases of drilling, completion or fracturing fluids or wastewater into the environment. These conditions can cause:

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disruption in operations;

substantial repair or remediate costs;

personal injury or loss of human life;

significant damage to or destruction of property, plant and equipment;

environmental pollution, including groundwater contamination;

impairment or suspension of operations; and

substantial revenue loss.

The occurrence of a significant event or adverse claim in excess of the insurance coverage that we maintain or that is not covered by insurance could have a material adverse effect on our liquidity, consolidated results of operations and consolidated financial condition. Any interruption in our services due to pipeline breakdowns or necessary maintenance or repairs could reduce sales revenues and earnings. In addition, claims for loss of oil and gas production and damage to formations can occur in the well services industry. Litigation arising from a catastrophic occurrence at a location where our equipment and services are being used may result in our being named as a defendant in lawsuits asserting large claims.

We do not have insurance against all foreseeable risks, either because insurance is not available or because of the high premium costs. The occurrence of an event not fully insured against or the failure of an insurer to meet its insurance obligations could result in substantial losses. In addition, we may not be able to maintain adequate insurance in the future at rates we consider reasonable. Insurance may not be available to cover any or all of the risks to which we are subject, or, even if available, it may be inadequate, or insurance premiums or other costs could rise significantly in the future so as to make such insurance prohibitively expensive.

The deterioration of the financial condition of our customers could adversely affect our business.

During times when the gas or crude oil markets weaken, our customers are more likely to experience financial difficulties, including being unable to access debt or equity financing, which could result in a reduction in our customers’ spending for our services. In addition, in the course of our business we hold accounts receivable from our customers. In the event of the financial distress or bankruptcy of a customer, we could lose all or a portion of such outstanding accounts receivable associated with that customer. Further, if a customer was to enter into bankruptcy, it could also result in the cancellation of all or a portion of our service contracts with such customer at significant expense or loss of expected revenues to us.

We may be required to take write‑downs of the carrying values of our long‑lived assets and finite‑lived intangible assets.

We evaluate our long‑lived assets, such as property and equipment, and finite‑lived intangible assets for impairment whenever events or changes in circumstances indicate that their carrying value may not be recoverable. Recoverability is measured by a comparison of their carrying amount to the estimated undiscounted cash flows to be generated by those assets. Based on specific market factors and circumstances at the time of prospective impairment reviews and the continuing evaluation of development plans, economics and other factors, we may be required to write down the carrying value of our long‑lived and finite‑lived intangible assets. For the year ended December 31, 2017, we did not record an impairment on our long‑lived assets or an impairment on our finite‑lived intangible assets.

We may be required to take a write‑down of the carrying value of goodwill.

We conduct our annual goodwill impairment assessment during the fourth quarter of each year, or more frequently if an event or circumstance indicates that they carrying value of reporting unit may exceed the fair value.

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When possible impairment is indicated, we value the implied goodwill to compare it with the carrying amount of goodwill. If the carrying amount of goodwill exceeds its implied fair value, an impairment charge is recorded. The fair value of goodwill is based on estimates and assumptions applied by us such as revenue growth rates, operating margins, weighted‑average costs of capital, market multiples, and future market conditions and as affected by numerous factors, including the general economic environment and levels of exploration and production activity of oil and gas companies, our financial performance and trends, and our strategies and business plans, among others. As a result of this annual impairment assessment, we may be required to write down the carrying value of goodwill. For the year ended December 31, 2017, we did not record an impairment on goodwill.

Seasonal weather conditions and natural disasters could severely disrupt normal operations and harm our business.

Our water solutions operations are located primarily in the southern, mid‑western and eastern United States. We also have fluids management operations in Western Canada. Certain of these areas are adversely affected by seasonal weather conditions, primarily in the winter and spring. During periods of heavy snow, ice or rain, we may be unable to move our equipment between locations, thereby reducing our ability to provide services and generate revenues. In particular, in Canada, wet weather and the spring thaw may make the ground unstable. Consequently, municipalities and provincial transportation departments enforce road bans that restrict the movement of rigs and other heavy equipment, thereby reducing activity levels. The timing and length of the road bans depend on weather conditions leading to the spring thaw and during the thawing period. Additionally, certain oil and gas producing areas are located in areas that are inaccessible other than during the winter months, because the ground surrounding the drilling sites in these areas consists of swampy terrain known as muskeg. Rigs and other necessary equipment cannot cross this terrain to reach the drilling site until the muskeg freezes. Additionally, extended drought conditions in our operating regions could impact our ability to source sufficient water for our customers or increase the cost for such water. As a result, a natural disaster or inclement weather conditions could severely disrupt the normal operation of our business and adversely impact our financial condition and results of operations.

We are subject to cyber security risks. A cyber incident could occur and result in information theft, data corruption, operational disruption and/or financial loss.

The oil and gas industry has become increasingly dependent on digital technologies to conduct certain processing activities. For example, we depend on digital technologies to perform many of our services and to process and record financial and operating data. At the same time, cyber incidents, including deliberate attacks or unintentional events, have increased. The U.S. government has issued public warnings that indicate that energy assets might be specific targets of cyber security threats. Our technologies, systems and networks, and those of our vendors, suppliers and other business partners, may become the target of cyberattacks or information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information, or other disruption of business operations. In addition, certain cyber incidents, such as surveillance, may remain undetected for an extended period. Our systems and insurance coverage for protecting against cyber security risks may not be sufficient. As cyber incidents continue to evolve, we may be required to expend additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyber incidents. Our insurance coverage for cyberattacks may not be sufficient to cover all the losses we may experience as a result of such cyberattacks.

A terrorist attack or armed conflict could harm our business.

The occurrence or threat of terrorist attacks in the United States, Canada or other countries, anti‑terrorist efforts and other armed conflicts involving the United States, Canada or other countries, including continued hostilities in the Middle East, may adversely affect the United States, Canada and global economies and could prevent us from meeting our financial and other obligations. If any of these events occur, the resulting political instability and societal disruption could reduce overall demand for oil and gas, potentially putting downward pressure on demand for our services and causing a reduction in our revenues. Oil and gas related facilities could be direct targets of terrorist attacks, and our operations could be adversely impacted if infrastructure integral to our customers’ operations is destroyed or damaged. Costs for insurance and other security may increase as a result of these threats, and some insurance coverage may become more difficult to obtain, if available at all.

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We engage in transactions with related parties and such transactions present possible conflicts of interest that could have an adverse effect on us.

We have entered into a significant number of transactions with related parties. Related party transactions create the possibility of conflicts of interest with regard to our management. Such a conflict could cause an individual in our management to seek to advance his or her economic interests above ours. Further, the appearance of conflicts of interest created by related party transactions could impair the confidence of our investors. Our board of directors regularly reviews these transactions. Notwithstanding this, it is possible that a conflict of interest could have a material adverse effect on our liquidity, results of operations and financial condition.

The adoption of more stringent trucking legislation or regulations may increase our costs and could have a material adverse effect on our liquidity, consolidated results of operations, and consolidated financial condition.

In connection with the services we provide in the United States and Canada, we operate as a motor carrier and therefore are subject to regulation by the U.S. DOT and analogous U.S. state agencies, and by Transport Canada and analogous provincial agencies. These regulatory authorities exercise broad powers, governing activities such as the authorization to engage in motor carrier operations and regulatory safety. There are additional regulations specifically relating to the trucking industry, including testing and specification of equipment and product handling requirements. The trucking industry is subject to possible legislative and regulatory changes that may affect the economics of the industry by requiring changes in operating practices or by changing the demand for common or contract carrier services or the cost of providing truckload services. Some of these possible changes include increasingly stringent environmental regulations and changes in the regulations that govern the amount of time a driver may drive in any specific period, onboard black box recorder devices or limits on vehicle weight and size.

In the United States, interstate motor carrier operations are subject to safety requirements developed and implemented by the U.S. DOT. Intrastate motor carrier operations often are subject to state safety regulations that mirror federal regulations. Such matters as weight and dimension of equipment are also subject to federal and state laws and regulations. In Canada, as the Canadian government continues to develop and propose regulations relating to fuel quality, engine efficiency and GHG emissions, we may experience an increase in costs related to truck purchases and maintenance, impairment of equipment productivity, a decrease in the residual value of vehicles, unpredictable fluctuations in fuel prices and an increase in operating expenses. Increased truck traffic may contribute to deteriorating road conditions in some areas where our operations are performed. Our operations, including routing and weight restrictions, could be affected by road construction, road repairs, detours and state and local regulations and ordinances restricting access to certain roads. In addition, proposals to increase taxes, including taxes on motor fuels, are also made from time to time, and any such increase would increase our operating costs. Also, local regulation of permitted routes and times on specific roadways could adversely affect our operations. We cannot predict whether, or in what form, any legislative or regulatory changes or municipal ordinances applicable to our logistics operations will be enacted and to what extent any such legislation or regulations could increase our costs or otherwise adversely affect our business or operations.

From time to time, various legislative proposals are introduced, including proposals to increase federal, state or local taxes, including taxes on motor fuels, which may increase our costs or adversely affect the recruitment of drivers. Management cannot predict whether, or in what form, any increase in such taxes applicable to us will be enacted. We may be required to increase operating expenses or capital expenditures in order to comply with any new laws, regulations or other restrictions.

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Disruptions in the transportation services of trucking companies transporting wastewater and other oilfield products could have a material adverse effect on our results.

We use trucks to transport some produced water to our wastewater disposal facilities, as well as to transport sand in the Rockies and Bakken areas. In recent years, certain states, such as North Dakota and Texas, and state counties have increased enforcement of weight limits on trucks used to transport raw materials on their public roads. It is possible that the states, counties and cities in which we operate our business may modify their laws to further reduce truck weight limits or impose curfews or other restrictions on the use of roadways. Such legislation and enforcement efforts could result in delays in, and increased costs to, transport produced water to our wastewater disposal facilities or to transport sand, which may either increase our operating costs or reduce the amount of produced water transported to our facilities or sand hauled for our customers. Such developments could decrease our operating margins or amounts of produced water or sand and thereby have a material adverse effect on our results of operations and financial condition.

A significant increase in fuel prices may adversely affect our transportation costs, which could have a material adverse effect on our results of operations and financial condition.

Fuel is one of our significant operating expenses, and a significant increase in fuel prices could result in increased transportation costs. The price and supply of fuel is unpredictable and fluctuates based on events such as geopolitical developments, supply and demand for oil and gas, actions by oil and gas producers, war and unrest in oil producing countries and regions, regional production patterns and weather concerns. A significant increase in fuel prices could increase the price of, and therefore reduce demand for, our services, which could affect our results of operations and financial condition.

Our Canadian operations subject us to currency translation risk, which could cause our results of operations and financial condition to fluctuate significantly from period to period.

A portion of our revenue is derived from our Canadian activities and operations. As a result, we translate the results of our operations and financial condition of our Canadian operations into U.S. dollars. Therefore, our reported results of operations and financial condition are subject to changes in the exchange rate between the two currencies. Fluctuations in foreign currency exchange rates could affect our revenue, expenses and operating margins. As we continue to expand our international operations, we become more exposed to the effects of fluctuations in currency exchange rates. Currently, we do not hedge our exposure to changes in foreign exchange rates.

Risks Related to our Class A Common Stock

We do not expect to pay any dividends to the holders of the Class A common stock in the foreseeable future and the availability and timing of future dividends, if any, is uncertain.

We currently intend to retain future earnings, if any, to finance the expansion of our business, including the repayment of our debt, and do not expect to declare or pay any dividends on our Class A common stock in the foreseeable future. Our Credit Agreement places certain restrictions on the ability of us and our subsidiaries to pay dividends. Consequently, your only opportunity to achieve a return on your investment in us will be if you sell your Class A common stock at a price greater than you paid for it. There is no guarantee that the price of our Class A common stock that will prevail in the market will ever exceed the price that you pay. We may amend our Credit Agreement or enter into new debt arrangements that also prohibit or restrict our ability to pay dividends on our Class A common stock.

Subject to such restrictions, our board of directors will determine the amount and timing of stockholder dividends, if any, that we may pay in future periods. In making this determination, our directors will consider all relevant factors, including the amount of cash available for dividends, capital expenditures, covenants, prohibitions or limitations with respect to dividends, applicable law, general operational requirements and other variables. We cannot predict the amount or timing of any future dividends you may receive, and if we do commence the payment of dividends, we may be unable to pay, maintain or increase dividends over time. Therefore, you may not be able to realize any return on your investment in our Class A common stock for an extended period of time, if at all. Please read “Item 5. Market for

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Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities—Dividend Policy.”

If certain conditions are not met, Special Dividends may accrue on the outstanding shares of our Class A-2 common stock which would be dilutive to the holders of our Class A common stock and Class B common stock.

If we fail to cause a resale shelf registration statement for the benefit of the holders of our Class A-2 common stock to go effective by March 31, 2018 as currently anticipated, Special Dividends (as defined in our amended and restated certificate of incorporation) will accrue with respect to the outstanding shares of our Class A-2 common stock. Special Dividends are non-cash dividends that are payable only in additional shares of Class A-2 common stock, resulting in dilution to the holders of our Class A common stock and Class B common stock that may be substantial. The holders of Class A-2 common stock will be given the benefit of any accrued Special Dividends for purposes of (i) voting at any meeting of stockholders (for so long as shares of Class A-2 common stock remain issued and outstanding), (ii) the receipt of any dividends declared on our common stock (other than Special Dividends) and (iii) the sale or transfer of shares of Class A-2 common stock, such that the right to receive any accrued and unpaid Special Dividends shall be transferred with and unseverable from the shares of Class A-2 common stock on which such Special Dividends accrue. Such Special Dividends will be issuable upon the occurrence of certain events; once issued, such shares will be convertible into shares of Class A common stock on the same terms and conditions as the Class A-2 common stock.

If we fail to develop or maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud. As a result, current and potential stockholders could lose confidence in our financial reporting, which would harm our business and the trading price of our Class A common stock.

Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and operate successfully as a public company. We are not currently required to comply with the SEC’s rules implementing Section 404 of the Sarbanes‑Oxley Act of 2002 (“Sarbanes-Oxley”) and therefore are not required to make a formal assessment of the effectiveness of our internal controls over financial reporting for that purpose. If we cannot provide reliable financial reports or prevent fraud, our reputation and operating results would be harmed. We cannot be certain that our efforts to develop and maintain our internal controls will be successful, that we will be able to maintain adequate controls over our financial processes and reporting in the future or that we will be able to comply with our obligations under Sections 302 and 404 of Sarbanes‑Oxley. Any failure to develop or maintain effective internal controls, or difficulties encountered in implementing or improving our internal controls, could harm our operating results or cause us to fail to meet our reporting obligations. Ineffective internal controls could also cause investors to lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our Class A common stock.

Since we are an “emerging growth company,” we are not required to comply with certain disclosure requirements that are applicable to other public companies and we cannot be certain if the reduced disclosure requirements applicable to emerging growth companies will make our Class A common stock less attractive to investors.

We are an “emerging growth company,” as defined in the Jumpstart Our Business Startups Act of 2012 (the “JOBS Act”) and we may take advantage of certain exemptions from various reporting requirements that are applicable to public companies, including, but not limited to, longer phase‑in periods for the adoption of new or revised financial accounting standards, not being required to comply with the auditor attestation requirements of Section 404 of Sarbanes‑Oxley, reduced disclosure obligations regarding executive compensation in our periodic reports and proxy statements, and exemptions from the requirements of holding a nonbinding advisory vote on executive compensation and stockholder approval of any golden parachute payments not previously approved. We intend to take advantage of all of the reduced reporting requirements and exemptions, including the longer phase‑in periods for the adoption of new or revised financial accounting standards under Section 107 of the JOBS Act, until we are no longer an emerging growth company. Our election to use the phase‑in periods permitted by this election may make it difficult to compare our financial statements to those of non‑emerging growth companies and other emerging growth companies that have opted out of the longer phase‑in periods under Section 107 of the JOBS Act and who will comply with new or revised financial accounting standards. If we were to subsequently elect instead to comply with these public company effective dates, such election would be irrevocable pursuant to Section 107 of the JOBS Act.

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We cannot predict if investors will find our Class A common stock less attractive because we will rely on these exemptions. If some investors find our Class A common stock less attractive as a result, there may be a less active trading market for our Class A common stock and our Class A common stock price may be more volatile. Under the JOBS Act, “emerging growth companies” can delay adopting new or revised accounting standards until such time as those standards apply to private companies.

We will remain an emerging growth company for up to five years, although we will lose that status sooner if we have more than $1.07 billion of revenues in a fiscal year, have more than $700 million in market value of our common stock held by non-affiliates as of any June 30 or issue more than $1.0 billion of non-convertible debt over a rolling three-year period.

Future sales of our equity securities, or the perception that such sales may occur, may depress our share price, and any additional capital raised through the sale of equity or convertible securities may dilute your ownership in us.

Subject to certain limitations and exceptions, SES Legacy Holdings, LLC (“Legacy Owner Holdco”) and its permitted transferees may exchange their SES Holdings LLC Units (together with a corresponding number of shares of Class B common stock) for shares of Class A common stock (on a one-for-one basis, subject to conversion rate adjustments for stock splits, stock dividends and reclassification and other similar transactions) and then sell those shares of Class A common stock. Additionally, we may in the future issue our previously authorized and unissued securities. We are authorized to issue 350 million shares of Class A common stock, 40 million shares of Class A-2 common stock, 150 million shares of Class B common stock and 50 million shares of preferred stock with such designations, preferences and rights as determined by our board of directors. The potential issuance of such additional shares of equity securities will result in the dilution of the ownership interests of the holders of our Class A common stock and may create downward pressure on the trading price, if any, of our Class A common stock.

In addition, Legacy Owner Holdco, Crestview Partners II SES Investment B, LLC, the SCF Group (as defined below) and WDC Aggregate LLC (collectively, the “Registration Rights Holders”), who collectively own approximately 60.5 million shares of our common stock, are party to a registration rights agreement which provides, among other things, for parties to that agreement to demand registration of all or a portion of their shares and to initiate or participate in certain underwritten offerings. Parties to such registration rights agreement may exercise their rights under such agreement in their sole discretion, and sales pursuant to such rights may be material in amount and occur at any time.

In connection with the closing of the Rockwater Merger, Rockwater assigned, and we assumed Rockwater’s rights and obligations under a registration rights agreement entered into by and between Rockwater and FBR Capital Markets & Co. Under such assumed registration rights agreement, we agreed, at our expense, to file with the SEC a shelf registration statement registering for resale shares of our Class A common stock into which the outstanding shares of our Class A-2 common stock are convertible, and to cause such registration statement to be declared effective by the SEC as soon as practicable but in any event by March 31, 2018.

The registration rights of the Registration Rights Holders and the holders of our Class A-2 common stock and the sales of substantial amounts of our Class A common stock following the effectiveness of registration statements for the benefit of such holders, or the perception that these sales may occur, could cause the market price of our Class A common stock to decline and impair our ability to raise capital. We also may grant additional registration rights in connection with any future issuance of our capital stock.

We cannot predict the size of future issuances of our Class A common stock or securities convertible into Class A common stock or the effect, if any, that future issuances and sales of shares of our Class A common stock will have on the market price of our Class A common stock. Sales of substantial amounts of our Class A common stock (including shares issued in connection with an acquisition), or the perception that such sales could occur, may adversely affect prevailing market prices of our Class A common stock.

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If securities or industry analysts do not publish research or reports about our business, if they adversely change their recommendations regarding our Class A common stock or if our operating results do not meet their expectations, the share price for our Class A common stock could decline.

The trading market for our Class A common stock will be influenced by the research and reports that industry or securities analysts publish about us or our business. If one or more of these analysts cease coverage of us or fail to publish reports on us regularly, we could lose visibility in the financial markets, which in turn could cause the price or trading volume of our Class A common stock to decline. Moreover, if one or more of the analysts who cover us downgrades our Class A common stock or if our operating results do not meet their expectations, the share price of our Class A common stock could decline.

Provisions in our amended and restated certificate of incorporation and amended and restated bylaws and Delaware law may discourage a takeover attempt even if a takeover might be beneficial to our stockholders. 

Provisions contained in our Third Amended and Restated Certificate of Incorporation and our Amended and Restated Bylaws, which we refer to herein as our “amended and restated certificate of incorporation” and “amended and restated bylaws,” respectively, could make it more difficult for a third party to acquire us. Provisions of our amended and restated certificate of incorporation and amended and restated bylaws impose various procedural and other requirements, which could make it more difficult for stockholders to effect certain corporate actions. For example, our amended and restated certificate of incorporation authorizes our board of directors to determine the rights, preferences, privileges and restrictions of unissued series of preferred stock without any vote or action by our stockholders. Thus, our board of directors can authorize and issue shares of preferred stock with voting or conversion rights that could adversely affect the voting or other rights of holders of our capital stock. These rights may have the effect of delaying or deterring a change of control of our company. Additionally, our amended and restated bylaws establish limitations on the removal of directors and on the ability of our stockholders to call special meetings and include advance notice requirements for nominations for election to our board of directors and for proposing matters that can be acted upon at stockholder meetings.  These provisions could limit the price that certain investors might be willing to pay in the future for shares of our Class A common stock.

In addition, certain change of control events have the effect of accelerating the payment due under our Tax Receivable Agreements (as defined herein), which could be substantial and accordingly serve as a disincentive to a potential acquirer of our company. See “—Risks Related to Our Organizational Structure—In certain cases, payments under the Tax Receivable Agreements may be accelerated and/or significantly exceed the actual benefits, if any, we realize in respect of the tax attributes subject to the Tax Receivable Agreements.”

Legacy Owner Holdco controls a significant percentage of our voting power.

Legacy Owner Holdco beneficially owns 89.2% of our Class B common stock and the Class B common stock represents approximately 33.9% of our outstanding voting capital stock. In addition, certain of our directors are currently employed by Crestview Advisors, L.L.C. (“Crestview Partners”), our private equity sponsor and, through Crestview Partners II GP, L.P. (“Crestview GP”), the manager of funds that hold the largest equity interest in Legacy Owner Holdco. Other funds controlled by Crestview GP also have an interest in our currently outstanding shares of our Class A common stock, representing an additional 3.6% of our outstanding voting capital. Collectively, these holders control approximately 37.4% of our voting shares. Holders of Class A common stock, Class A‑2 common stock and Class B common stock generally will vote together as a single class on all matters presented to our stockholders for their vote or approval. Consequently, Legacy Owner Holdco will be able to strongly influence all matters that require approval by our stockholders, including the election and removal of directors, changes to our organizational documents and approval of acquisition offers and other significant corporate transactions, regardless of whether other stockholders believe that a transaction is in their own best interests. This concentration of ownership will limit your ability to influence corporate matters, and as a result, actions may be taken that you may not view as beneficial.

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Our amended and restated certificate of incorporation contains a provision renouncing our interest and expectancy in certain corporate opportunities, which could adversely affect our business or prospects.

Our amended and restated certificate of incorporation provides that, to the fullest extent permitted by applicable law, we renounce any interest or expectancy in any business opportunity that involves any aspect of the energy business or industry and that may be from time to time presented to any member of (i) Legacy Owner Holdco; Crestview Partners II SES Investment, LLC (‘‘Crestview Holdings A’’); any funds, limited partnerships or other investment entities or vehicles managed by Crestview Partners or controlled by Crestview GP; B-29 Investments, LP; Sunray Capital, LP; Proactive Investments, LP and their respective affiliates, other than us (collectively, the ‘‘SES Group’’); (ii) SCF-VI, L.P., SCF-VII, L.P. and SCF-VII(A), L.P. and their respective affiliates, other than us (collectively, the ‘‘SCF Group’’); (iii) the other entities (existing and future) that participate in the energy industry and in which the SES Group and SCF Group own substantial equity interests (the ‘‘Portfolio Companies’’) or (iv) any director or officer of the corporation who is also an employee, partner, member, manager, officer or director of any member of the SES Group, the SCF Group or the Portfolio Companies, including our Executive Chairman, John D. Schmitz, our director, David C. Baldwin, and our Executive Vice President, Business Strategy, Cody Ortowski, even if the opportunity is one that we might

reasonably have pursued or had the ability or desire to pursue if granted the opportunity to do so. Mr. Schmitz controls both B-29 Investments, LP and Sunray Capital, LP and is a direct and indirect beneficiary of these provisions in our amended and restated certificate of incorporation. Our amended and restated certificate of incorporation further provides that no such person or party shall be liable to us by reason of the fact that such person pursues any such business opportunity, or fails to offer any such business opportunity to us.

As a result, any member of the SES Group, SCF Group or the Portfolio Companies or any director or officer of the corporation who is also an employee, partner, member, manager, officer or director of any member of the SES Group, SCF Group or the Portfolio Companies may become aware, from time to time, of certain business opportunities, such as acquisition opportunities, and may direct such opportunities to other businesses in which they have invested, in which case we may not become aware of or otherwise have the ability to pursue such opportunity. Further, such businesses may choose to compete with us for these opportunities. As a result, by renouncing our interest and expectancy in any business opportunity that may be from time to time presented to any member of the SES Group, SCF Group or the Portfolio Companies or any director or officer of the corporation who is also an employee, partner, member, manager, officer or director of any member of the SES Group, SCF Group or the Portfolio Companies, our business or prospects could be adversely affected if attractive business opportunities are procured by such parties for their own benefit rather than for ours. See “Item 13. Certain Relationships and Related Transactions, and Director Independence.”

A significant reduction by Crestview GP or the SCF Group of either of their respective ownership interests in us could adversely affect us.

We believe that Crestview GP’s and the SCF Group’s beneficial ownership interests in us provides each with an economic incentive to assist us to be successful. Neither Crestview GP nor the SCF Group is subject to any obligation to maintain its ownership interest in us and either may elect at any time to sell all or a substantial portion of or otherwise reduce its ownership interest in us. If either Crestview GP or the SCF Group sells all or a substantial portion of its ownership interest in us, it may have less incentive to assist in our success and its affiliate(s) that are expected to serve as members of our board of directors may resign. Such actions could adversely affect our ability to successfully implement our business strategies which could adversely affect our cash flows or results of operations.

We may issue preferred stock whose terms could adversely affect the voting power or value of our Class A common stock.

Our amended and restated certificate of incorporation authorizes us to issue, without the approval of our stockholders, one or more classes or series of preferred stock having such designations, preferences, limitations and relative rights, including preferences over our Class A common stock respecting dividends and distributions, as our board of directors may determine. The terms of one or more classes or series of preferred stock could adversely impact the voting power or value of our Class A common stock. For example, we might grant holders of preferred stock the right to elect some number of our directors in all events or on the happening of specified events or the right to veto

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specified transactions. Similarly, the repurchase or redemption rights or liquidation preferences we might assign to holders of preferred stock could affect the residual value of the Class A common stock.

Our amended and restated certificate of incorporation designates the Court of Chancery of the State of Delaware as the sole and exclusive forum for certain types of actions and proceedings that may be initiated by our stockholders, which could limit our stockholders’ ability to obtain a favorable judicial forum for disputes with us or our directors, officers, employees or agents.

Our amended and restated certificate of incorporation provides that, unless we consent in writing to the selection of an alternative forum, the Court of Chancery of the State of Delaware will, to the fullest extent permitted by applicable law, be the sole and exclusive forum for (i) any derivative action or proceeding brought on our behalf, (ii) any action asserting a claim of breach of a fiduciary duty owed by any of our directors, officers, employees or agents to us or our stockholders, (iii) any action asserting a claim against us or any director or officer or other employee or agent of ours arising pursuant to any provision of the Delaware General Corporation Law, our amended and restated certificate of incorporation or our amended and restated bylaws, or (iv) any action asserting a claim against us or any director or officer or other employee or agent of ours that is governed by the internal affairs doctrine, in each such case subject to such Court of Chancery having personal jurisdiction over the indispensable parties named as defendants therein. To the fullest extent permitted by law, any person or entity purchasing or otherwise acquiring any interest in shares of our capital stock will be deemed to have notice of, and consented to, the provisions of our amended and restated certificate of incorporation described in the preceding sentence. This choice of forum provision may limit a stockholder’s ability to bring a claim in a judicial forum that it finds favorable for disputes with us or our directors, officers, employees or agents, which may discourage such lawsuits against us and such persons. Alternatively, if a court were to find these provisions of our amended and restated certificate of incorporation inapplicable to, or unenforceable in respect of, one or more of the specified types of actions or proceedings, we may incur additional costs associated with resolving such matters in other jurisdictions, which could adversely affect our business, financial condition or results of operations.

Risks Related to Our Organizational Structure

We are a holding company. Our sole material asset is our equity interest in SES Holdings, and accordingly, we are dependent upon distributions and payments from SES Holdings to pay taxes, make payments under the Tax Receivable Agreements and cover our corporate and other overhead expenses.

We are a holding company and have no material assets other than our equity interest in SES Holdings. We have no independent means of generating revenue. To the extent SES Holdings has available cash, we intend to cause SES Holdings to make (i) generally pro rata distributions to its unitholders, including us, in an amount at least sufficient to allow us to pay our taxes and to make payments under the Tax Receivable Agreements that we entered into in connection with our restructuring at the Select 144A Offering and any subsequent tax receivable agreements that we may enter into in connection with future acquisitions and (ii) non‑pro rata payments to us to reimburse us for our corporate and other overhead expenses. We will be limited, however, in our ability to cause SES Holdings and its subsidiaries to make these and other distributions or payments to us due to certain limitations, including the restrictions under our Credit Agreement and the cash requirements and financial condition of SES Holdings. To the extent that we need funds and SES Holdings or its subsidiaries are restricted from making such distributions or payments under applicable law or regulations or under the terms of their financing arrangements or are otherwise unable to provide such funds, our liquidity and financial condition could be adversely affected.

We will be required to make payments under the Tax Receivable Agreements for certain tax benefits we may claim, and the amounts of such payments could be significant.

In connection with our restructuring at the Select 144A Offering, we entered into two tax receivable agreements (the “Tax Receivable Agreements”) with certain affiliates of the then-holders of SES Holdings LLC Units (the “TRA Holders”) which generally provide for the payment by us to the TRA Holders of 85% of the net cash savings, if any, in U.S. federal, state and local income and franchise tax that we actually realize (computed using simplifying assumptions to address the impact of state and local taxes) or are deemed to realize in certain circumstances as a result of certain tax basis increases, net operating losses available to us as a result of certain reorganization transactions entered into in connection with the Select 144A Offering, and certain tax benefits attributable to imputed interest. We will retain the benefit of the remaining 15% of these cash savings.

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The term of each Tax Receivable Agreement commenced upon the completion of the Select 144A Offering and will continue until all tax benefits that are subject to such Tax Receivable Agreement have been utilized or expired, unless we exercise our right to terminate the Tax Receivable Agreements (or the Tax Receivable Agreements are terminated due to other circumstances, including our breach of a material obligation thereunder or certain mergers or other changes of control) and we make the termination payment specified in the Tax Receivable Agreements. In addition, payments we make under the Tax Receivable Agreements will be increased by any interest accrued from the due date (without extensions) of the corresponding tax return. In the event that the Tax Receivable Agreements are not terminated and we have sufficient taxable income to utilize all of the tax benefits subject to the Tax Receivable Agreements, the payments due under the Tax Receivable Agreement entered into with Legacy Owner Holdco and Crestview GP are expected to commence in late 2018 and to continue for 20 years after the date of the last exchange of SES Holdings LLC Units, and the payments due under the Tax Receivable Agreement entered into with an affiliate of the Contributing Legacy Owners are expected to commence in late 2019 and to continue for 25 taxable years following the Select 144A Offering.

The payment obligations under the Tax Receivable Agreements are our obligations and not obligations of SES Holdings, and we expect that the payments we will be required to make under the Tax Receivable Agreements will be substantial. Estimating the amount and timing of payments that may become due under the Tax Receivable Agreements is by its nature imprecise. For purposes of the Tax Receivable Agreements, cash savings in tax generally will be calculated by comparing our actual tax liability (using the actual applicable U.S. federal income tax rate and an assumed combined state and local income and franchise tax rate) to the amount we would have been required to pay had we not been able to utilize any of the tax benefits subject to the Tax Receivable Agreements. The amounts payable, as well as the timing of any payments, under the Tax Receivable Agreements are dependent upon future events and significant assumptions, including the timing of the exchanges of SES Holdings LLC Units, the market price of our Class A common stock at the time of each exchange (since such market price will determine the amount of tax basis increases resulting from the exchange), the extent to which such exchanges are taxable transactions, the amount of the exchanging unitholder’s tax basis in its SES Holdings LLC Units at the time of the relevant exchange, the depreciation and amortization periods that apply to the increase in tax basis, the amount of net operating losses available to us as a result of reorganization transactions entered into in connection with the Select 144A Offering, the amount and timing of taxable income we generate in the future, the U.S. federal income tax rate then applicable, and the portion of our payments under the Tax Receivable Agreements that constitute imputed interest or give rise to depreciable or amortizable tax basis.

Certain of the TRA Holders’ rights under the Tax Receivable Agreements are transferable in connection with a permitted transfer of SES Holdings LLC Units or if the TRA Holder no longer holds SES Holdings LLC Units. The payments under the Tax Receivable Agreements are not conditioned upon the continued ownership interest in either SES Holdings or us of any holder of rights under the Tax Receivable Agreements. See “Item 13. Certain Relationships and Related Transactions, and Director Independence.”

In certain cases, payments under the Tax Receivable Agreements may be accelerated and/or significantly exceed the actual benefits, if any, we realize in respect of the tax attributes subject to the Tax Receivable Agreements.

If we elect to terminate the Tax Receivable Agreements early or they are terminated early due to our failure to honor a material obligation thereunder or due to certain mergers, asset sales, other forms of business combinations or other changes of control, our obligations under the Tax Receivable Agreements would accelerate and we would be required to make an immediate payment equal to the present value of the anticipated future payments to be made by us under the Tax Receivable Agreements (determined by applying a discount rate of the lesser of 6.50% per annum, compounded annually, or one‑year London Interbank Offered Rate (“LIBOR”) plus 100 basis points); and such payment is expected to be substantial. The calculation of anticipated future payments will be based upon certain assumptions and deemed events set forth in the Tax Receivable Agreements, including (i) the assumption that we have sufficient taxable income to fully utilize the tax benefits covered by the Tax Receivable Agreements, (ii) the assumption that any SES Holdings LLC Units (other than those held by us) outstanding on the termination date are exchanged on the termination date and (iii) certain loss or credit carryovers will be utilized in the taxable year that includes the termination date. Any early termination payment may be made significantly in advance of the actual realization, if any, of the future tax benefits to which the termination payment relates.

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As a result of either an early termination or a “change of control” (as defined in the Tax Receivable Agreements, as amended), we could be required to make payments under the Tax Receivable Agreements that exceed our actual cash tax savings under the Tax Receivable Agreements. In these situations, our obligations under the Tax Receivable Agreements could have a substantial negative impact on our liquidity and could have the effect of delaying, deferring or preventing certain mergers, asset sales or other forms of business combinations or changes of control. For example, if the Tax Receivable Agreements were terminated on December 31, 2017, the estimated termination payments would have been approximately $98.9 million (calculated using a discount rate equal to the lesser of 6.50% per annum, compounded annually, or one-year LIBOR plus 100 basis points, applied against an undiscounted liability of $130.6 million, based upon the last reported closing sale price of our Class A common stock on December 31, 2017) in the aggregate. The foregoing number is merely an estimate and the actual payment could differ materially. There can be no assurance that we will be able to finance our obligations under the Tax Receivable Agreements.

Payments under the Tax Receivable Agreements will be based on the tax reporting positions that we will determine. The TRA Holders will not reimburse us for any payments previously made under the Tax Receivable Agreements if any tax benefits that have given rise to payments under the Tax Receivable Agreements are subsequently disallowed, except that excess payments made to the TRA Holders will be netted against payments that would otherwise be made to the TRA Holders, if any, after our determination of such excess. As a result, in such circumstances, we could make payments that are greater than our actual cash tax savings, if any, and may not be able to recoup those payments, which could adversely affect our liquidity. See “Item 13. Certain Relationships and Related Transactions, and Director Independence.”

If SES Holdings were to become a publicly traded partnership taxable as a corporation for U.S. federal income tax purposes, we and SES Holdings might be subject to potentially significant tax inefficiencies, and we would not be able to recover payments previously made by us under the Tax Receivable Agreements even if the corresponding tax benefits were subsequently determined to have been unavailable due to such status.

We intend to operate such that SES Holdings does not become a publicly traded partnership taxable as a corporation for U.S. federal income tax purposes. A “publicly traded partnership” is a partnership, the interests of which are traded on an established securities market or are readily tradable on a secondary market or the substantial equivalent thereof. Under certain circumstances, exchanges of SES Holdings LLC Units for shares of our Class A common stock or cash pursuant to the Eighth Amended and Restated Limited Liability Company Agreement of SES Holdings (the “SES Holdings LLC Agreement”) or other transfers of SES Holdings LLC Units could cause SES Holdings to be treated as a publicly traded partnership. Applicable U.S. Treasury regulations provide for certain safe harbors from treatment as a publicly traded partnership, and we intend to operate such that exchanges or other transfers of SES Holdings LLC Units qualify for one or more such safe harbors. For example, we intend to limit the number of unitholders of SES Holdings and Legacy Owner Holdco, and the SES Holdings LLC Agreement, provides for limitations on the ability of unitholders of SES Holdings to transfer their SES Holdings LLC Units and will provide us, as managing member of SES Holdings, with the right to impose restrictions (in addition to those already in place) on the ability of unitholders of SES Holdings to exchange their SES Holdings LLC Units pursuant to the SES Holdings LLC Agreement to the extent we believe it is necessary to ensure that SES Holdings will continue to be treated as a partnership for U.S. federal income tax purposes. If SES Holdings were to become a publicly traded partnership, significant tax inefficiencies might result for us and for SES Holdings. In addition, we may not be able to realize tax benefits covered under the Tax Receivable Agreements, and we would not be able to recover any payments previously made by us under the Tax Receivable Agreements, even if the corresponding tax benefits (including any claimed increase in the tax basis of SES Holdings’ assets) were subsequently determined to have been unavailable.

Legacy Owner Holdco and the Legacy Owners may have interests that conflict with holders of shares of our Class A common stock.

Legacy Owner Holdco owns approximately 33.9% of the outstanding SES Holdings LLC Units. Because it holds a portion of its ownership interest in our business in the form of direct ownership interests in SES Holdings rather than through us, Legacy Owner Holdco may have conflicting interests with holders of shares of Class A common stock. For example, Legacy Owner Holdco may have different tax positions from us, and decisions we make in the course of running our business, such as with respect to mergers, asset sales, other forms of business combinations or other changes

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in control, may affect the timing and amount of payments that are received by the TRA Holders under the Tax Receivable Agreements. See “Item 13. Certain Relationships and Related Transactions, and Director Independence.”

Our ability to use Rockwater’s net operating loss carryforwards may be limited.

As of December 31, 2017, Rockwater had approximately $105.9 million of U.S. federal net operating loss carryforwards (“NOLs”), which will begin to expire in 2035, approximately $77.4 million of state NOLs which will begin to expire in 2020, and approximately $14.5 million of foreign NOLs, which will begin to expire in 2035. Utilization of these NOLs depends on many factors, including our future income, which cannot be assured. In addition, Section 382 of the Internal Revenue Code of 1986, as amended (the “Code”), generally imposes an annual limitation on the amount of NOLs that may be used to offset taxable income when a corporation has undergone an “ownership change” (as determined under Section 382 of the Code). An ownership change generally occurs if one or more stockholders (or groups of stockholders) who are each deemed to own at least 5% of the relevant corporation’s stock change their ownership by more than 50 percentage points over their lowest ownership percentage within a rolling three‑year period. In the event that an ownership change has occurred, or were to occur, utilization of the NOLs would be subject to an annual limitation under Section 382 of the Code, determined by multiplying the value of the relevant corporation’s stock at the time of the ownership change by the applicable long‑term tax‑exempt rate as defined in Section 382 of the Code, and potentially increased for certain gains recognized within five years after the ownership change if we have a net built‑in gain in our assets at the time of the ownership change. Any unused annual limitation may be carried over to later years until they expire. Rockwater experienced an ownership change in connection with the Rockwater Merger. As a result, some or all of our U.S. federal, state or foreign NOLs could expire before they can be used. In addition, future ownership changes or changes to the U.S. tax laws could limit our ability to utilize our NOLs. To the extent we are not able to offset our future income with our NOLs, this would adversely affect our operating results and cash flows if we attain profitability.

Future regulations relating to and interpretations of recently enacted U.S. federal income tax legislation may vary from our current interpretation of such legislation.

The U.S. federal income tax legislation recently enacted in Public Law No. 115-97, commonly referred to as the Tax Cuts and Jobs Act, is highly complex and subject to interpretation. The presentation of our financial condition and results of operations is based upon our current interpretation of the provisions contained in the Tax Cuts and Jobs Act. In the future, the Treasury Department and the Internal Revenue Service are expected to release regulations relating to and interpretive guidance of the legislation contained in the Tax Cuts and Jobs Act. Any significant variance of our current interpretation of such legislation from any future regulations or interpretive guidance could result in a change to the presentation of our financial condition and results of operations and could negatively affect our business.

ITEM 1B.           UNRESOLVED STAFF COMMENTS

None.

ITEM 2.              PROPERTIES

We lease space for our principal executive offices in Houston, Texas. We also lease local office space in the countries in which we operate. Additionally, we own and lease numerous, storage facilities, trucking facilities and sales and administrative offices throughout the geographic area in which we operate. In connection with our Oilfield Chemicals segment, we own and lease, three primary manufacturing facilities in Texas and 5 regional distribution centers to provide products to our customers in all major U.S. shale basins. Our leased properties are subject to various lease terms and expirations

 

We believe all properties that we currently occupy are suitable for their intended uses. We believe that our current facilities are sufficient to conduct our operations. However, we continue to evaluate the purchase or lease of additional properties or the sale or consolidation of our properties, as our business requires.

 

53


 

The following table shows our active owned and leased properties categorized by geographic region as of December 31, 2017:

 

 

 

 

 

 

 

Region

 

Office, Repair & Service and Other

 

Manufacturing

 

Operational Field Services Facilities

United States

 

 

 

 

 

 

Owned

 

 1

 

 3

 

28

Leased

 

 8

 

 -

 

66

Canada

 

 

 

 

 

 

Owned

 

 3

 

 -

 

 -

Leased

 

 -

 

 -

 

14

Total

 

12

 

 3

 

108

 

 

ITEM 3.              LEGAL PROCEEDINGS 

We are not currently a party to any legal proceedings that, if determined adversely against us, individually or in the aggregate, would have a material adverse effect on our financial position, results of operations or cash flows. We are, however, named defendants in certain lawsuits, investigations and claims arising in the ordinary course of conducting our business, including certain environmental claims and employee‑related matters, and we expect that we will be named defendants in similar lawsuits, investigations and claims in the future. While the outcome of these lawsuits, investigations and claims cannot be predicted with certainty, we do not expect these matters to have a material adverse impact on our business, results of operations, cash flows or financial condition. We have not assumed any liabilities arising out of these existing lawsuits, investigations and claims.

In December 2016, Rockwater was notified by the U.S. Attorney’s Office for the Middle District of Pennsylvania that it is being investigated for altering emissions control systems on several of its vehicles. We are cooperating with the investigation and have determined that mechanics servicing our vehicle fleet may have installed software on certain vehicles and modified a few other vehicles to deactivate or bypass the factory‑installed emissions control systems. At present, it appears that 31 vehicles in Pennsylvania were modified in this manner, apparently to improve vehicle performance and reliability. As a result of a company‑wide investigation undertaken voluntarily and in cooperation with the U.S. Department of Justice, we have determined that approximately 30 additional company vehicles outside of Pennsylvania may have been altered. As of the date of the initiation of the investigation, we operated approximately 1,400 vehicles in the U.S., and the modified vehicles constituted less than 5% of our fleet at such time. We are unable to predict at this time whether any administrative, civil or criminal charges will be brought against us, although we have learned that at least one employee, a service shop supervisor, may be the target of a criminal investigation, and it is possible that other individuals or we could become targets. We are cooperating with the U.S. Department of Justice in all aspects of the investigation and have instituted procedures to ensure that our mechanics do not tamper with or bypass any emissions control systems when they are performing vehicle maintenance, and we have also reached an agreement with the U.S. Department of Justice providing for either the restoration or removal from service of those vehicles that were modified. Although we are unable to predict the outcome of this investigation, we note that in similar circumstances, the EPA has imposed fines of up to $7,200 per altered vehicle and has also required the responsible party to disgorge any financial benefit that it may have derived.

ITEM 4.              MINE SAFETY DISCLOSURE

Not applicable.

54


 

PART II

ITEM 5.              MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Price Range of Common Stock and Dividends

Our Class A common stock began trading on the New York Stock Exchange (the “NYSE”) under the ticker symbol “WTTR” on April 21, 2017. Prior to that, there was no public market for our common stock. The table below sets forth, for the periods indicated, the high and low sales prices per share of our Class A common stock since April 21, 2017, our first trading date.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

WTTR share

 

Dividends

 

 

 

High

 

Low

 

Per Share

 

2017

 

 

Second Quarter (1)

 

$

16.60

 

$

11.38

 

$

0.00

 

Third Quarter

 

$

17.25

 

$

11.22

 

$

0.00

 

Fourth Quarter

 

$

18.44

 

$

14.44

 

$

0.00

 


(1)

For the period from April 21, 2017 through June 30, 2017.

On March 15, 2018, the closing price of our Class A common stock was $13.63. As of March 15, 2018, there were 59,290,665 shares of our Class A common stock outstanding, held of record by 147 holders, 40,331,989 shares of our Class B common stock outstanding, held by seven holders and 6,731,839 shares of our Class A-2 common stock outstanding, held by three holders. The foregoing numbers of holders of our common stock do not include DTC participants or beneficial owners holding shares through nominee names.

Dividend Policy

We have not paid dividends to holders of our Class A common stock. We do not anticipate declaring or paying any cash dividends to holders of our Class A common stock in the foreseeable future. We currently intend to retain future earnings, if any, to finance the expansion of our business. Our future dividend policy is within the discretion of our board of directors and will depend upon then-existing conditions, including our results of operations and financial condition, capital requirements, business prospects, statutory and contractual restrictions on our ability to pay dividends, including restrictions contained in our Credit Agreement and other factors our board of directors may deem relevant.

Holders of shares of our Class A-2 common stock issued in connection with the Rockwater Merger are entitled to receive Special Dividends that will accrue and be payable only in additional shares of Class A-2 common stock if certain conditions are not met. For additional information, please read "Item 1A. Risk Factors—If certain conditions are not met, Special Dividends may accrue on the outstanding shares of our Class A-2 common stock which would be dilutive to the holders of our Class A common stock and Class B common stock.”

55


 

Unregistered Sales of Equity Securities and Use of Proceeds

Unregistered Sales of Equity Securities

On November 1, 2017, in connection with the closing of the Rockwater Merger and pursuant to the Merger Agreement, we issued 26,246,115 shares of Class A common stock, 6,731,845 shares of Class A‑2 common stock and 4,356,477 shares of Class B common stock (along with a corresponding number of SES Holdings LLC Units) to the former stockholders of Rockwater. At the same time, we issued approximately 37,334,437 SES Holdings LLC Units to the former holders of Rockwater LLC Units. These issuances of our common stock did not involve any underwriters, underwriting discounts or commissions or a public offering. We believe these issuances were exempt from registration pursuant to Section 4(a)(2) of the Securities Act and Rule 506 of Regulation D promulgated thereunder based on representations to us from each former Rockwater stockholder to support such exemption, including with respect to each former Rockwater stockholder’s status as an “accredited investor” (as that term is defined in Rule 501(a) of Regulation D promulgated under Section 4(a)(2) of the Securities Act). The shares of Class A‑2 common stock will automatically convert into shares of our Class A common stock on a one‑for‑one basis upon the effectiveness of a shelf registration statement registering such shares for resale. The shares of SES Holdings LLC Units (along with the corresponding number of Class B common stock) are convertible into shares of Class A common stock upon the satisfaction of certain conditions.

On October 31, 2017, following the distribution by Legacy Owner Holdco of SES Holdings LLC Units and shares of our Class B common stock in redemption of certain of its members (the “SES Redeemed Legacy Holders”), we exercised our right to require an exchange by such SES Redeemed Legacy Holders, pursuant to which SES Holdings distributed 2,487,029 shares of our Class A common stock to such SES Redeemed Legacy Holders in exchange for 2,487,029 SES Holdings LLC Units. This issuance of Class A common stock did not involve any underwriters, underwriting discounts or commissions or a public offering. We believe this issuance was exempt from registration pursuant to Section 4(a)(2) of the Securities Act. In connection with the exchange, the 2,487,029 shares of Class B common stock were cancelled.

Issuer Purchases of Equity Securities

Neither we nor any affiliated purchaser repurchased any of our equity securities during the period covered by this Annual Report on Form 10‑K.

 

ITEM 6.              SELECTED FINANCIAL DATA

The following table presents our selected historical data for the periods and as of the dates indicated. The statement of operations data for the years ended December 31, 2017, 2016 and 2015 and balance sheet data as of December 31, 2017 and 2016 were derived from our audited historical consolidated financial statements. The historical selected financial data should be read in conjunction with “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the historical consolidated financial statements and related notes thereto included in “Item 8. Financial Statements and Supplementary Data.”

56


 

 

 

 

 

 

 

 

 

 

 

 

 

Year Ended December 31, 

 

 

2017

 

2016

 

2015

 

 

(in thousands)

Revenue

 

 

 

 

 

 

 

 

 

Water solutions and related services

 

$

546,043

 

$

241,455

 

$

427,496

Accommodations and rentals

 

 

53,888

 

 

27,151

 

 

52,948

Wellsite completion and construction services

 

 

50,974

 

 

33,793

 

 

55,133

Oilfield chemical product sales

 

 

41,586

 

 

 —

 

 

 —

Total revenue

 

 

692,491

 

 

302,399

 

 

535,577

Costs of revenue

 

 

   

 

 

   

 

 

  

Water solutions and related services

 

 

411,215

 

 

200,399

 

 

332,411

Accommodations and rentals

 

 

41,885

 

 

22,019

 

 

37,957

Wellsite completion and construction services

 

 

42,942

 

 

29,089

 

 

48,356

Oilfield chemical product sales

 

 

37,024

 

 

 —

 

 

 —

Depreciation and amortization

 

 

101,645

 

 

95,020

 

 

104,608

Total costs of revenue

 

 

634,711

 

 

346,527

 

 

523,332

Gross profit (loss)

 

 

57,780

 

 

(44,128)

 

 

12,245

Operating expenses

 

 

   

 

 

   

 

 

  

Selling, general and administrative

 

 

82,403

 

 

34,643

 

 

56,548

Depreciation and amortization

 

 

1,804

 

 

2,087

 

 

3,104

Impairment of goodwill and other intangible assets

 

 

 —

 

 

138,666

 

 

21,366

Impairment of property and equipment

 

 

 —

 

 

60,026

 

 

 —

Lease abandonment costs

 

 

3,572

 

 

19,423

 

 

 —

Total operating expenses

 

 

87,779

 

 

254,845

 

 

81,018

Loss from operations

 

 

(29,999)

 

 

(298,973)

 

 

(68,773)

Other income (expense)

 

 

   

 

 

   

 

 

  

Interest expense, net

 

 

(6,629)

 

 

(16,128)

 

 

(13,689)

Foreign currency gains, net

 

 

281

 

 

 —

 

 

 —

Other income, net

 

 

369

 

 

629

 

 

893

Loss before tax expense

 

 

(35,978)

 

 

(314,472)

 

 

(81,569)

Tax benefit (expense)

 

 

851

 

 

524

 

 

(324)

Net loss from continuing operations

 

 

(35,127)

 

 

(313,948)

 

 

(81,893)

Net income from discontinued operations, net of tax

 

 

 —

 

 

 —

 

 

21

Net loss

 

 

(35,127)

 

 

(313,948)

 

 

(81,872)

Less: net loss attributable to Predecessor

 

 

 —

 

 

306,481

 

 

80,891

Less: net loss attributable to noncontrolling interests

 

 

18,311

 

 

6,424

 

 

981

Net loss attributable to Select Energy Services, Inc.

 

$

(16,816)

 

$

(1,043)

 

$

 —

Allocation of net loss attributable to:

 

 

  

 

 

  

 

 

  

Class A stockholders

 

$

(12,560)

 

$

(199)

 

 

  

Class A-1 stockholders

 

 

(3,691)

 

 

(844)

 

 

  

Class A-2 stockholders

 

 

(565)

 

 

 —

 

 

 

Class B stockholders

 

 

 —

 

 

 —

 

 

  

 

 

$

(16,816)

 

$

(1,043)

 

 

  

Weighted average shares outstanding:

 

 

  

 

 

  

 

 

  

Class A—Basic & Diluted

 

 

24,612,853

 

 

3,802,972

 

 

  

Class A-1—Basic & Diluted

 

 

7,233,973

 

 

16,100,000

 

 

  

Class A-2—Basic & Diluted

 

 

1,106,605

 

 

 —

 

 

 

Class B—Basic & Diluted

 

 

38,768,156

 

 

38,462,541

 

 

  

 

 

 

 

 

 

 

 

 

 

Net loss per share attributable to common stockholders:

 

 

 

 

 

 

 

 

  

Class A—Basic & Diluted

 

$

(0.51)

 

$

(0.05)

 

 

  

Class A-1—Basic & Diluted

 

$

(0.51)

 

$

(0.05)

 

 

  

Class A-2—Basic & Diluted

 

$

(0.51)

 

$

 —

 

 

 

Class B—Basic & Diluted

 

$

 —

 

$

 —

 

 

  

 

 

 

 

 

 

 

 

 

 

Statement of Cash Flow Data:

 

 

 

 

 

 

 

 

 

Net cash provided by (used in):

 

 

 

 

 

 

 

 

 

Operating activities

 

$

(2,899)

 

$

5,131

 

$

151,999

Investing activities

 

 

(156,731)

 

 

(26,955)

 

 

(38,703)

Financing activities

 

 

122,397

 

 

45,560

 

 

(107,348)

Balance Sheet Data (at period end):

 

 

 

 

 

 

 

 

 

Cash and cash equivalents

 

$

2,774

 

$

40,041

 

$

16,305

Total assets

 

 

1,356,368

 

 

405,066

 

 

650,248

Long-term liabilities

 

 

107,806

 

 

23,974

 

 

256,923

Other Financial Data:

 

 

 

 

 

 

 

 

 

 

 

(unaudited)

EBITDA(1)

 

$

74,100

 

$

(201,237)

 

$

39,853

Adjusted EBITDA(1)

 

 

117,262

 

 

16,944

 

 

65,539

 

57


 


(1)We define EBITDA as net income/(loss), plus interest expense, taxes, and depreciation and amortization. We define Adjusted EBITDA as EBITDA plus/(minus) loss/(income) from discontinued operations, plus any impairment charges or asset write‑offs pursuant to accounting principles generally accepted in the United States (“GAAP”), plus/(minus) non‑cash losses/(gains) on the sale of assets or subsidiaries, non‑recurring compensation expense, non‑cash compensation expense, and non‑recurring or unusual expenses or charges, including severance expenses, transaction costs, or facilities‑related exit and disposal‑related expenditures, plus/(minus) foreign currency losses/(gains) and plus any inventory write-down. Our board of directors, management and investors use EBITDA and Adjusted EBITDA to assess our financial performance because it allows them to compare our operating performance on a consistent basis across periods by removing the effects of our capital structure (such as varying levels of interest expense), asset base (such as depreciation and amortization) and non‑recurring items outside the control of our management team. We present EBITDA and Adjusted EBITDA because we believe they provide useful information regarding the factors and trends affecting our business in addition to measures calculated under GAAP.

EBITDA and Adjusted EBITDA each have limitations as an analytical tool and should not be considered as alternatives to net income, operating income, cash flow from operating activities or any other measure of financial performance presented in accordance with GAAP. Other companies in our industry may calculate EBITDA or Adjusted EBITDA differently, limiting its usefulness as a comparative measure.

The following table shows a reconciliation of (i) EBITDA and Adjusted EBITDA, as applicable, to the most directly comparable GAAP measure, net loss.

 

 

 

 

 

 

 

 

 

 

 

 

Year Ended December 31, 

 

    

2017

    

2016

 

2015

 

 

(in thousands)

Net loss

 

$

(35,127)

 

$

(313,948)

 

$

(81,872)

Interest expense

 

 

6,629

 

 

16,128

 

 

13,689

Tax (benefit) expense

 

 

(851)

 

 

(524)

 

 

324

Depreciation and amortization

 

 

103,449

 

 

97,107

 

 

107,712

EBITDA

 

 

74,100

 

 

(201,237)

 

 

39,853

Net income from discontinued operations

 

 

 —

 

 

 —

 

 

(21)

Impairment

 

 

 —

 

 

198,692

 

 

21,366

Lease abandonment costs

 

 

3,572

 

 

19,423

 

 

 —

Non-recurring severance expenses (1)

 

 

4,161

 

 

886

 

 

3,200

Non-recurring transaction costs (2)

 

 

10,179

 

 

(236)

 

 

2,790

Non-cash compensation expenses

 

 

7,691

 

 

(487)

 

 

(889)

Non-cash (gain) loss on sale of subsidiaries and other assets

 

 

1,740

 

 

(97)

 

 

(760)

Non-recurring phantom equity and IPO-related compensation

 

 

12,537

 

 

 —

 

 

 —

Foreign currency gains

 

 

(281)

 

 

 —

 

 

 —

Other non-recurring charges

 

 

3,563

 

 

 —

 

 

 —

Adjusted EBITDA

 

$

117,262

 

$

16,944

 

$

65,539


(1)

For 2017, these costs are associated with severance incurred in connection with the Rockwater Merger. For 2016 and 2015, these costs are associated with the reduction in headcount as a result of the industry downturn.

(2)

For 2017, these costs are primarily associated with the Rockwater Merger and GRR Acquisition. For 2016 and 2015, these transaction costs are associated with our evaluation and negotiation of various transactions that never materialized.

 

 

58


 

ITEM 7.              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 should be read in conjunction with our consolidated financial statements and related notes thereto in “Item 8. Financial Statements and Supplementary Data”. This discussion and analysis contains forward-looking statements based upon our current expectations that involve risks and uncertainties. Our actual results may differ materially from those anticipated in these forward-looking statements as a result of various factors as described under “Cautionary Note Regarding Forward-Looking Statements” and “Item 1A. Risk Factors.” We assume no obligation to update any of these forward‑looking statements.

Overview

We are a leading provider of total water management and chemical solutions to the unconventional oil and gas industry in the United States and Western Canada. Within the major shale plays in the United States, we believe we are a market leader in sourcing, transfer (both by permanent pipeline and temporary hose) and temporary containment of water prior to its use in drilling and completion activities associated with hydraulic fracturing or “fracking,” which we collectively refer to as “pre‑frac water services,” as well as testing and flowback services immediately following the well completion. In most of our areas of operations, we also provide additional complementary water‑related services that support oil and gas well completion and production activities including monitoring, treatment, hauling and water recycling and disposal. We also develop and manufacture a full suite of specialty chemicals used in well completions and production chemicals used to enhance performance over the life of a well. Our services are necessary to establish and maintain production of oil and gas over the productive life of a well. Water and related services are increasingly important as oil and gas E&P companies have increased the complexity and completion intensity of horizontal wells (including the use of longer horizontal wellbore laterals, tighter spacing of frac stages in the laterals and increased water, proppant and chemical use per foot of lateral) in order to improve production and recovery of hydrocarbons. We have historically generated a substantial majority of our revenues through providing total water solutions to our customers, and we believe we are the only company that provides total water solutions together with complementary chemical products and related expertise, which we believe gives us a unique competitive advantage in our industry.

Rockwater Merger 

On November 1, 2017, we completed the Rockwater Merger in which we combined with Rockwater. Rockwater was a provider of comprehensive water management solutions to the oil and gas industry in the United States and Canada. Rockwater and its subsidiaries provided water sourcing, transfer, testing, monitoring, treatment and storage; site and pit surveys; flowback and well testing; water reuse services; water testing; and fluids logistics. Rockwater also developed and manufactured a full suite of specialty chemicals used in well completions, and production chemicals used to enhance performance over the life of a well. The total consideration for the Rockwater Merger was $620.2 million, in which we issued 25.9 million shares of our Class A common stock, 6.7 million shares of our Class A-2 common stock and 4.4 million shares of our Class B common to the former holders of Rockwater common stock and a unit-for-unit transaction in which SES Holdings issued approximately 37.3 million SES Holdings LLC Units to the former holders of units in Rockwater LLC.

Resource Water Acquisition

On September 15, 2017, we completed our acquisition of Resource Water. Resource Water provides water transfer services to E&P operators in West Texas and East Texas. Resource Water’s assets include 24 miles of layflat hose as well as numerous pumps and ancillary equipment required to support water transfer operations. Resource Water has longstanding customer relationships across its operating regions which are viewed as strategic to our water solutions business.

59


 

GRR Acquisition

On March 10, 2017, we completed our acquisition of the GRR Entities. The GRR Entities provide water and water‑related services to E&P companies in the Permian Basin and own and have rights to a vast array of fresh, brackish and effluent water sources with access to significant volumes of water annually and water transport infrastructure, including over 900 miles of temporary and permanent pipeline infrastructure and related storage facilities and pumps, all located in the northern Delaware Basin portion of the Permian Basin. The total consideration we paid for this acquisition was approximately $59.6 million, with $53.0 million paid in cash,  $5.5 million paid in shares of Class A common stock, subject to customary post‑closing adjustments, and $1.1 million in assumed tax liabilities to the sellers. We funded the cash portion of the consideration for the GRR Acquisition with $19.0 million of cash on hand and $34.0 million of borrowings under our Previous Credit Facility, which we repaid with a portion of the net proceeds of the IPO. We believe this acquisition has significantly enhanced our position in the Permian Basin.

Going forward, we intend to pursue selected, accretive acquisitions of complementary assets, businesses and technologies, including water transfer infrastructure, and believe we are well positioned to capture attractive opportunities due to our market position, customer relationships and industry experience and expertise.

Our Segments

Following the completion of the Rockwater Merger, we offer our services through the following three operating segments: (i) Water Solutions, (ii) Oilfield Chemicals and (iii) Wellsite Services.

Water Solutions.  Our Water Solutions segment is operated primarily under our subsidiary, Select LLC, and provides water‑related services to customers that include major integrated oil companies and independent oil and natural gas producers. These services include: the sourcing of water; the transfer of the water to the wellsite through permanent pipeline infrastructure and temporary hose; the containment of fluids off‑ and on‑location; measuring and monitoring of water; the filtering and treatment of fluids, well testing and handling of flowback and produced formation water; and the transportation and recycling or disposal of drilling, completion and production fluids.

Oilfield Chemicals.  Our Oilfield Chemicals segment is operated primarily under our subsidiary, Rockwater LLC, and develops, manufactures and provides a full suite of chemicals utilized in hydraulic fracturing, stimulation, cementing and well completions, including polymers that create viscosity, crosslinkers, friction reducers, surfactants, buffers, breakers and other chemical technologies, to leading pressure pumping service companies in the United States. We also provide production chemicals solutions, which are applied to underperforming wells in order to enhance well performance and reduce production costs through the use of production treating chemicals, corrosion and scale monitoring, chemical inventory management, well failure analysis and lab services.

Wellsite Services.  Our Wellsite Services segment provides a number of services across the U.S. and Canada and is operated primarily under our subsidiaries Peak, Affirm and Rockwater LLC. Peak provides workforce accommodations and surface rental equipment supporting drilling, completion and production operations to the U.S. onshore oil and gas industry. Affirm provides oil and gas operators with a variety of services, including crane and logistics services, wellsite and pipeline construction and field services. Operating under Rockwater LLC, we also offer sand hauling and logistics services in the Rockies and Bakken regions as well as water transfer, containment, fluids hauling and other rental services in Western Canada.

How We Generate Revenue

We currently generate a significant majority of our revenue through our Water Solutions segment, specifically through total water management associated with hydraulic fracturing. We generate our revenue through customer agreements with fixed pricing terms but no guaranteed throughput amounts. While we have some long‑term pricing

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arrangements, most of our water and water‑related services are priced based on prevailing market conditions, giving due consideration to the specific requirements of the customer.

We also generate revenue through our Oilfield Chemicals segment, which provides completion, specialty chemicals and production chemicals, and our Wellsite Services segment, which provides workforce accommodations and related rentals; a variety of wellsite completion and construction services, including wellsite construction, pipeline construction, field services and well services; sand hauling and fluids logistics services; and water transfer, fluids hauling, containment and rentals services in Canada. We invoice the majority of our Oilfield Chemicals customers for services provided under such segment based on the quantity of chemicals used or pursuant to short‑term contracts as the customer’s needs arise. We invoice the majority of our customers for services under our Wellsite Services segments on a per job basis or pursuant to short‑term contracts as the customer’s needs arise.

Costs of Conducting Our Business

The principal expenses involved in conducting our business are labor costs, equipment costs (including depreciation, repair and maintenance and leasing costs), raw materials and water sourcing costs and fuel costs. Our fixed costs are relatively low and a large portion of the costs we incur in our business are only incurred when we provide water, water‑related services, chemicals and chemical‑related services to our customers.

Labor costs associated with our employees represent the most significant costs of our business. We incurred labor costs of $259.6 million,  $140.3 million and $235.8 million for the years ended December 31, 2017, 2016 and 2015, respectively. Our labor costs for the year ended December 31, 2017 included $12.5 million of non-recurring costs related to a payout on our phantom equity units and IPO success bonuses. The majority of our recurring labor costs are variable and are incurred only while we are providing water and water-related services. We also incur costs to employ personnel to sell and supervise our services and perform maintenance on our assets which are not directly tied to our level of business activity. We also incur selling, general and administrative costs for compensation of our administrative personnel at our field sites and in our corporate headquarters. 

We incur significant equipment costs in connection with the operation of our business, including depreciation, repair and maintenance and leasing costs. We incurred equipment costs of $153.4 million,  $111.8 million and $145.1 million for the years ended December 31, 2017, 2016 and 2015, respectively. Our depreciation costs are expected to increase over the next few years as a result of the Rockwater Merger.

We incur significant transportation cost associated with our service lines, including fuel and freight. We incurred fuel costs of $39.7 million,  $17.3 million and $31.2 million for the years ended December 31, 2017, 2016 and 2015, respectively. Fuel prices impact our transportation costs, which affect the pricing and demand of our services, and have an impact on our results of operations.

We incur raw material costs in manufacturing our chemical products, as well as water sourcing costs in connection with obtaining strategic and reliable water sources to provide repeatable water volumes to our customers. We incurred raw material costs of $32.0 million from Rockwater’s operations from the date of the Rockwater Merger on November 1, 2017 to December 31, 2017. We incurred water sourcing costs of $45.3 million,  $21.9 million and $27.6 million for the years ended December 31, 2017,  2016 and 2015, respectively. 

Public Company Costs

General and administrative expenses related to being a publicly traded company include: Exchange Act reporting expenses; expenses associated with compliance with Sarbanes‑Oxley; expenses associated with maintaining our listing on the NYSE; incremental independent auditor fees; incremental legal fees; investor relations expenses; registrar and transfer agent fees; incremental director and officer liability insurance costs; and director compensation. We expect that general and administrative expenses related to being a publicly traded company will increase in future periods. Costs incurred by us for corporate and other overhead expenses will be reimbursed by SES Holdings pursuant to the SES Holdings LLC Agreement.

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How We Evaluate Our Operations

We use a variety of operational and financial metrics to assess our performance. Among other measures, management considers each of the following:

Revenue;

Gross Profit;

EBITDA; and

Adjusted EBITDA.

Revenue

We analyze our revenue and assess our performance by comparing actual monthly revenue to our internal projections. We also assess incremental changes in revenue compared to incremental changes in direct operating costs, and selling, general and administrative expenses across our operating segments to identify potential areas for improvement, as well as to determine whether segments are meeting management’s expectations.

Gross Profit

To measure our financial performance, we analyze our gross profit, which we define as revenues less direct operating expenses (including depreciation and amortization expenses). We believe gross profit is a meaningful metric because it provides insight on profitability and true operating performance based on the historical cost basis of our assets. We also compare gross profit to prior periods and across segments to identify underperforming segments.

EBITDA and Adjusted EBITDA

We view EBITDA and Adjusted EBITDA as important indicators of performance. We define EBITDA as net income/(loss), plus interest expense, taxes, and depreciation and amortization. We define Adjusted EBITDA as EBITDA plus/(minus) loss/(income) from discontinued operations, plus any impairment charges or asset write‑offs pursuant to GAAP, plus/(minus) non‑cash losses/(gains) on the sale of assets or subsidiaries, non‑recurring compensation expense, non‑cash compensation expense, and non‑recurring or unusual expenses or charges, including severance expenses, transaction costs, or facilities‑related exit and disposal‑related expenditures, plus/(minus) foreign currency losses/(gains) and plus any inventory write-down. See “—Comparison of Non‑GAAP Financial Measures” for more information and a reconciliation of EBITDA and Adjusted EBITDA to net income (loss), the most directly comparable financial measure calculated and presented in accordance with GAAP.

Factors Affecting the Comparability of Our Results of Operations to Our Historical Results of Operations

Our future results of operations may not be comparable to our historical results of operations for the periods presented, primarily for the reasons described below.

Acquisition Activity

As described above, we are continuously evaluating potential investments, particularly in water transfer, infrastructure and other water‑related services. To the extent we consummate acquisitions, any incremental revenues or expenses from such transactions would not be included in our historical results of operations.

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Rockwater Merger

On November 1, 2017, we completed the Rockwater Merger whereby we acquired the business, assets and operations of Rockwater. Our historical financial statements for periods prior to November 1, 2017 do not include the results of operations of Rockwater.

Resource Water Acquisition

On September 15, 2017, we completed our acquisition of Resource Water. Our historical financial statements for periods prior to September 15, 2017 do not include the results of operations of Resource Water.

GRR Acquisition

On March 10, 2017, we completed our acquisition of GRR Entities. Our historical financial statements for periods prior to March 10, 2017 do not include the results of operations of the GRR Entities.

Impact of Industry Conditions on Our Operating Results

Demand for oilfield services depends substantially on drilling, completion and production activity by E&P companies, which, in turn, depends largely upon the current and anticipated profitability of developing oil and natural gas reserves. Beginning in the second half of 2014, oil prices began a rapid and significant decline that continued through the first half of 2016. This decline led to a significant contraction on demand for oilfield services and significantly and negatively impacted our operating results. Beginning in the third quarter of 2016, oil prices began to recover, as did demand for our services. In the discussion of our operating results below, we reference the fluctuations in industry conditions in connection with certain changes in our results of operations.

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Results of Operations

The following tables set forth our results of operations for the periods presented, including revenue by segment.

Year Ended December 31, 2017 Compared to the Year Ended December 31, 2016

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Year ended December 31, 

 

Change

 

 

    

2017

    

2016

    

Dollars

    

Percentage

 

 

 

 

(in thousands)

 

 

 

 

 

 

Revenue

 

 

  

 

 

  

 

 

  

 

  

 

Water solutions

 

$

528,309

 

$

241,455

 

$

286,854

 

118.8

%

Oilfield chemicals

 

 

41,586

 

 

 —

 

 

41,586

 

NM

 

Wellsite services

 

 

122,596

 

 

60,944

 

 

61,652

 

101.2

%

Total revenue

 

 

692,491

 

 

302,399

 

 

390,092

 

129.0

%

 

 

 

 

 

 

 

 

 

 

 

 

 

Costs of revenue

 

 

  

 

 

  

 

 

 

 

 

 

Water solutions

 

 

395,887