Smart Sand, Inc. - Annual Report: 2017 (Form 10-K)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549  

FORM 10-K

For the Annual Period Ended December 31, 2017

OR

For the Transition Period from ___ to ___

Commission file number 001-37936

SMART SAND, INC.

(Exact name of registrant as specified in its charter)

1725 Hughes Landing Blvd, Suite 800

The Woodlands, Texas 77380

(Address of principal executive offices) (Zip Code)

(281) 231-2660

(Registrant’s telephone number)

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

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

Indicate by check mark 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 Securities Exchange Act of 1934.    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 period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  ☒    No  ☐

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  ☒    No  ☐

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, 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. (Check one):

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).    Yes ☐    No  ☒

Number of shares of common shares outstanding, par value $0.001 per share as of March 12, 2018: 40,946,060.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant’s proxy statement for the 2018 Annual Meeting of Stockholders are incorporated herein by reference in Part III of this Annual Report on Form 10-K. Such proxy statement will be filed with the Securities and Exchange Commission within 120 days of the registrant’s fiscal year ended December 31, 2017.

TABLE OF CONTENTS

PART I

NOTE ABOUT FORWARD-LOOKING STATEMENTS

This Annual Report on Form 10-K contains forward-looking statements that are subject to risks and uncertainties. All statements other than statements of historical fact included in this Annual Report on Form 10-K are forward-looking statements. Forward-looking statements give our current expectations and projections relating to our financial condition, results of operations, plans, objectives, future performance and business. You can identify forward-looking statements by the fact that they do not relate strictly to historical or current facts. These statements may include words such as "anticipate,'' “estimate,'' "expect," "project," "plan," "intend," "believe," "may," "will," "should," "can have," "likely" and other words and terms of similar meaning in connection with any discussion of the timing or nature of future operating or financial performance or other events. For example, all statements we make relating to our estimated and projected costs, expenditures, cash flows, growth rates and financial results, our plans and objectives for future operations, growth or initiatives, strategies or the expected outcome or impact of pending or threatened litigation are forward-looking statements. All forward-looking statements are subject to risks and uncertainties that may cause actual results to differ materially from those that we expected, including without limitation:

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We derive many of our forward-looking statements from our operating budgets and forecasts, which are based on many detailed assumptions. While we believe that our assumptions are reasonable, we caution that it is very difficult to predict the impact of known factors, and it is impossible for us to anticipate all factors that could affect our actual results. Important factors that could cause actual results to differ materially from our expectations, or cautionary statements, are disclosed under Item I A, "Risk Factors" and Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations" in this Annual Report on Form 10-K. All written and oral forward-looking statements attributable to us, or persons acting on our behalf, are expressly qualified in their entirety by these cautionary statements as well as other cautionary statements that are made from time to time in our other filings with the Securities and Exchange Commission (the "SEC") and public communications. You should evaluate all forward-looking statements made in this Annual Report on Form 10-K in the context of these risks and uncertainties.

We caution you that the important factors referenced above may not contain all of the factors that are important to you. In addition, we cannot assure you that we will realize the results or developments we expect or anticipate or, even if substantially realized, that they will result in the consequences or affect us or our operations in the way we expect. The forward-looking statements included in this Annual Report on Form 10-K are made only as of the date hereof. We undertake no obligation to update or revise any forward-looking statement as a result of new information, future events or otherwise, except as otherwise required by law.

Item 1. – Business

Overview

We are a pure-play, low-cost producer of high-quality Northern White raw frac sand, which is a preferred proppant used to enhance hydrocarbon recovery rates in the hydraulic fracturing of oil and natural gas wells. We sell our products primarily to oil and natural gas exploration and production companies and oilfield service companies under a combination of long-term take-or-pay contracts and spot sales in the open market. We believe that the size and favorable geologic characteristics of our sand reserves and the strategic location and logistical advantages of our facilities have positioned us as a highly attractive source of raw frac sand to the oil and natural gas industry. We incorporated in Delaware in July 2011.

We own and operate a raw frac sand mine and related processing facility near Oakdale, Wisconsin, at which we have approximately 321 million tons of proven recoverable sand reserves as of December 31, 2017. We began operations with 1.1 million tons of nameplate processing capacity in July 2012, expanded to 2.2 million tons of nameplate capacity in August 2014 and increased to 3.3 million tons in September 2015. Our integrated Oakdale facility, with on-site rail infrastructure and wet and dry sand processing facilities, has access to two Class I rail lines that allows us to ship on a unit train basis on either rail carrier and currently enables us to process and cost-effectively deliver up to approximately 3.3 million tons of raw frac sand per year. We are in the process of expanding our processing facilities at Oakdale to enable us to process and sell up to approximately 5.5 million tons of raw frac sand per year.  We expect this expansion will be completed and operational in the second quarter of 2018.

In addition to the Oakdale facility, we own a second property in Jackson County, Wisconsin, which we call the Hixton site. The Hixton site is also located adjacent to a Class I rail line and is fully permitted to initiate operations and is available for future development. As of December 31, 2017, our Hixton site had approximately 100 million tons of proven recoverable sand reserves.

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We have also entered into two long-term surface mining leases for properties located in the Permian Basin in Texas that are available for future development.  The first site consists of 1,772 acres in Winkler County, Texas.  This location is adjacent to the Texas & New Mexico Railway (TXN) short line with direct access to State Highway 18.  The second site consists of 2,447 acres in Crane County, Texas. This location has direct access to Interstate Highway 20 and has been awarded a Certificate of Inclusion into the Texas Conservation Plan (“TCP”) for the dunes sagebrush lizard. The TCP is designed to protect dunes sagebrush lizard habitat while facilitating continued and uninterrupted economic activity in the Permian Basin. The Permian Basin sites have been acquired for a combined cost of less than $5,000,000 and have low associated royalty payments. We estimate that the sites collectively have several hundred million tons of frac sand reserves.

For the years ended December 31, 2017, 2016 and 2015, we generated net income of approximately $21.5 million, $10.4 million and $5.0 million, respectively, and Adjusted EBITDA of approximately $30.6 million, $37.8 million and $23.9 million, respectively. For the definition of Adjusted EBITDA and a reconciliation to its most directly comparable financial measure calculated and presented in accordance with U.S. Generally Accepted Accounting Principles (“GAAP”), please read “Note Regarding Non-GAAP Financial Measures.”  For more financial information about our business, please read “Selected Financial Data”.

Over the past decade, exploration and production companies have increasingly focused on exploiting the vast hydrocarbon reserves contained in North America’s unconventional oil and natural gas reservoirs by utilizing advanced techniques, such as horizontal drilling and hydraulic fracturing. In recent years, this focus has resulted in exploration and production companies drilling more and longer horizontal wells, completing more hydraulic fracturing stages per well and utilizing more proppant per stage in an attempt to maximize the volume of hydrocarbon recoveries per wellbore. Spears and Associates, Inc. (“Spears”) expects proppant levels per well to continue to increase from 7,100 tons per well in 2018 to approximately 7,700 tons per well in 2020.  In addition, raw frac sand continues to be the preferred proppant used by operators.  Spears estimates that raw frac sand represented approximately 97% of total proppant demand in 2017 as exploration and production companies continued to look closely at overall well cost, completion efficiency and design optimization, which led to a greater use of raw frac sand in comparison to resin-coated sand and manufactured ceramic proppants.

Northern White raw frac sand, which is found predominantly in Wisconsin and limited portions of Minnesota and Illinois, is highly valued by oil and natural gas producers as a preferred proppant due to its favorable physical characteristics. We believe that the market for high-quality raw frac sand, like the Northern White raw frac sand we produce, will grow based on the potential recovery in the development of North America’s unconventional oil and natural gas reservoirs as well as the increased proppant volume usage per well, particularly with respect to finer mesh sizes. We expect the trend of using larger volumes of finer mesh materials, such as 100 mesh sand and 40/70 sand, to continue.

Competitive Strengths

We believe that we will be able to successfully execute our business strategies because of the following competitive strengths:

We believe our reserve base positions us well to take advantage of current market trends of increasing demand for finer mesh raw frac sand. Approximately 80% of our reserve mix today is 40/70 mesh substrate and 100 mesh substrate, considered to be the finer mesh substrates of raw frac sand. We believe that if oil and natural gas exploration and production companies continue recent trends in drilling and completion techniques to increase lateral lengths per well, the number of frac stages per well, the amount of proppant used per stage and the utilization of slickwater completions, the demand for the finer grades of raw frac sand will continue to increase, which we can take advantage of due to the high percentage of high-quality, fine mesh sand in our reserve base.

We also believe that having our mine, processing facilities and primary rail loading facilities at our Oakdale facility provides us with an overall low-cost structure, which enables us to compete effectively for sales of raw frac sand and to achieve attractive operating margins. The proximity of our mine, processing plants and primary rail loading facilities at one location eliminates the need for us to truck sand on public roads between the mine and the production facility or between wet and drying processing facilities, eliminating additional costs to produce and ship our sand.

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In addition to the Oakdale facility, we own the Hixton site in Jackson County, Wisconsin. The Hixton site is a second location adjacent to a Class I rail line that is fully permitted to initiate operations and is available for future development. As of December 31, 2017, our Hixton site had approximately 100 million tons of proven recoverable sand reserves. We have also optioned two properties in the Permian Basin of West Texas under long term leases and are currently evaluating options to develop one or both of these sites into fully operational raw frac sand mines to primarily support the growing demand for raw frac sand in the Permian Basin.  We acquired these locations at a low upfront cost and with minimal ongoing required royalty payments, which allows us time to evaluate potential market demand to support any investment in developing one or both of these sites on a cost-effective basis.

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Business Strategies

Our principal business objective is to be a pure-play, low-cost producer of high-quality raw frac sand and to increase stockholder value. We expect to achieve this objective through the following business strategies:

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Our Customers and Contracts

We sell raw frac sand under long-term take-or-pay contracts as well as in the spot market if we have excess production and the spot market conditions are favorable. As of March 1, 2018, we will have approximately 91.7% of our current annual nameplate capacity of 3.3 million tons per year contracted with a volume-weighted average remaining term of approximately 2.4 years.

Demand for proppants in 2015 and through the first half of 2016 dropped due to the downturn in commodity prices since late 2014 and the corresponding reduction in oil and natural gas drilling, completion and production activity. The change in demand during this period impacted contract discussions and negotiated terms with our customers as existing contracts were adjusted, resulting in a combination of reduced average selling prices per ton, and adjustments to take-or-pay volumes and lengths of contracts. We believe we have mitigated the short-term negative impact on revenues of some of these adjustments through contractual shortfall and reservation payments. During the market downturn, customers began to purchase more volumes on a spot basis as compared to committing to long-term contracts, and this trend continued until oil and natural gas drilling and completion activity began to increase beginning in the fourth quarter of 2016. In 2017, drilling and completion activity returned to higher levels, and we believe customers will begin to more actively consider contracting proppant volumes under term contracts rather than continuing to rely on buying proppant on a spot basis in the market.

Capital Plans

Based on our assessment of increased demand for our products, particularly fine mesh sand, we have decided to increase our annual nameplate processing capacity at our Oakdale facility to 5.5 million tons of raw frac sand. We have also decided to expand rail and logistics infrastructure in Wisconsin to support this potential increase in customer demand. Additionally, we continue to evaluate other proposed projects and related expenditures, such as investments in transload facilities and last mile solutions located in the shale operating basins, in light of customer demand and energy market trends. There can be no assurance, however, that all or any of these initiatives will be executed or that the results therefrom will be materially beneficial to our financial performance.

Industry Trends Impacting Our Business

Unless otherwise indicated, the information set forth under “—Industry Trends Impacting Our Business,” including all statistical data and related forecasts, is derived from The Freedonia Group’s Industry Study #3535, “Proppants Market in North America,” published in July 2017, Spears’ “Hydraulic Fracturing Market 2006 - 2018” published in the fourth quarter of 2017 and the supplement published in the first quarter of 2018, and Baker Hughes’ “North America Rotary Rig Count” published in February 2018. While we are not aware of any misstatements regarding the proppant industry data presented herein, estimates involve risks and uncertainties and are subject to change based on various factors, including those discussed under the heading “Risk Factors”.

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Demand Trends

According to Spears, the U.S. proppant market, including raw frac sand, ceramic and resin-coated proppant, was approximately 103 million tons in 2017. Freedonia estimates that the total raw frac sand market in 2017 represented approximately 96.5% of the total proppant market by weight. According to Spears, market demand in 2017 increased by approximately 41% from the prior record set in 2014. Spears estimates that over the next three years proppant demand will grow by 12.5% per year, from 103 million tons per year in 2017 to 165 million tons per year in 2020, representing an increase of approximately 62 million tons in annual proppant demand over that time period.

Demand growth for raw frac sand and other proppants is primarily driven by advancements in oil and natural gas drilling and well completion technology and techniques, such as horizontal drilling and hydraulic fracturing. These advancements have made the extraction of oil and natural gas increasingly cost-effective in formations that historically would have been uneconomic to develop. While current horizontal rig counts have fallen significantly from their peak of approximately 1,370 in 2014 to approximately 800 at the end of 2017, rig count grew 254% from the recent low of approximately 315 rigs in May of 2016 to approximately 800 at the end of 2017. According to the Baker Hughes Rig Count, the percentage of active drilling rigs used to drill horizontal wells, which require greater volumes of proppant than vertical wells, has increased from 68.4% in 2014 to 83.9% in 2017. Moreover, the increase of pad drilling has led to a more efficient use of rigs, allowing more wells to be drilled per rig. As a result of these factors, well count, and hence proppant demand, has grown despite the fall in rig counts. Spears estimates that proppant demand will reach 142 million tons in 2018, which is nearly twice the 2014 levels of approximately 73 million tons, despite their projection assuming that approximately 4,600 fewer wells will be drilled in 2018 as compared to 2014. Spears also estimates that average proppant usage per well will be approximately 7,100 tons per well in 2018 and will rise to approximately 7,700 tons per well by 2020.

Demand for proppant has sharply increased since 2016 in connection with the ongoing recovery in commodity prices and the corresponding increase in oil and natural gas drilling and production activity. We believe that the demand for proppant will continue to increase over the medium and long term as commodities stabilize from their lows in 2016, which will lead producers to continue to draw down their inventory of drilled but uncompleted wells and undertake new drilling activities. Further, we believe that demand for proppant will be amplified by the following factors:

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Recent growth in demand for raw frac sand has outpaced growth in demand for other proppants, and industry analysts predict that this trend will continue. As well completion costs have increased as a proportion of total well costs, operators have increasingly looked for ways to improve per well economics by lowering costs without sacrificing production performance. To this end, the oil and natural gas industry is shifting away from the use of higher-cost proppants towards more cost-effective proppants, such as raw frac sand. Evolution of completion techniques and the substantial increase in activity in U.S. oil and liquids-rich resource plays has further accelerated the demand growth for raw frac sand.

Historically, oil and liquids-rich wells use a higher proportion of coarser proppant while dry gas wells typically use finer grades of sand. In the past, with the majority of U.S. exploration and production spending focused on oil and liquids-rich plays, demand for coarser grades of sand exceeded demand for finer grades; however, due to innovations in completion techniques, demand for finer grade sands has shown a considerable resurgence.

Supply Trends

In 2017, customer demand for high-quality raw frac sand outpaced supply. Several factors contributed to this supply shortage, including:

Supplies of high-quality Northern White raw frac sand are limited to select areas, predominantly in western Wisconsin and limited areas of Minnesota and Illinois. The ability to obtain large contiguous reserves in these areas is a key constraint and can be an important supply consideration when assessing the economic viability of a potential raw frac sand facility. Further constraining the supply and throughput of Northern White raw frac sand is that not all of the large reserve mines have onsite excavation and processing capability. Additionally, much of the capital investment in Northern White raw frac sand mines was used to develop coarser deposits in western Wisconsin. With the shift to finer sands in the liquid and oil plays, many mines may not be economically viable as their ability to produce finer grades of sand may be limited.

Permits

We operate in a highly regulated environment overseen by many government regulatory and enforcement bodies at the local, state and federal levels. To conduct our mining operations, we are required to have obtained permits and approvals that address environmental, land use and safety issues at our Oakdale facility, Byron transload facility and our Hixton mine location. Our current and planned areas for excavation at our Oakdale property are permitted for extraction of our proven reserves. Portions of our Oakdale property lie in areas designated as wetlands, which will require additional local, state and federal permits prior to mining and reclaiming those areas.

We also meet requirements for several international standards concerning safety, greenhouse gases and rail operations. We have voluntarily agreed to meet the standards of the Wisconsin DNR’s “Green Tier” program, the “National Industrial Sand Association” (“NISA”) and the “Wisconsin Industrial Sand Association.” Further, we have agreed to meet the standards required to maintain our ISO 9001-2015 and ISO 14001-2015 quality/environmental management system registrations. These voluntary requirements are tracked and managed along with our permits. In addition, one of our land leases in the Permian Basin has been awarded a Certificate of Inclusion into the TCP for the dunes sagebrush lizard.  The TCP is designed to protect dunes sagebrush lizard habitat while facilitating continued and uninterrupted economic activity in the Permian Basin.

While resources invested in securing permits are significant, this cost has not had a material adverse effect on our results of operations or financial condition. We cannot ensure that existing environmental laws and regulations will not be reinterpreted or revised or that new environmental laws and regulations will not be adopted or become applicable to us. Revised or additional environmental requirements that result in increased compliance costs or additional operating restrictions could have a material adverse effect on our business.

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Our Customers and Contracts

Our core customers are major oil and natural gas exploration and production and oilfield service companies. These customers have signed long-term take-or-pay contracts, which mitigate our risk of non-performance by such customers. Our contracts provide for a true-up payment in the event the customer does not take delivery of the minimum annual volume of raw frac sand specified in the contract and has not purchased in certain prior periods an amount exceeding the minimum volume, resulting in a shortfall. The true-up payment is designed to compensate us, at least in part, for our margins for the applicable contract year and is calculated by multiplying the contract price (or, in some cases, a discounted contract price) by the tonnage shortfall. Any sales of the shortfall volumes to other customers on the spot market would provide us with additional margin on these volumes. Additionally, some of our contracts include monthly reservation charges that the customer is required to pay for minimum monthly volumes regardless of whether the customer takes delivery of the sand. For the year ended December 31, 2017, Rice Energy, Liberty, Weatherford, and US Well Services accounted for 27.1%, 20.6%, 13.7%, 10.2%, respectively, of our total revenues, and the remainder of our revenues represented sales to sixteen customers. For the year ended December 31, 2016, EOG Resources, US Well Services, Weatherford and Nabors Completion & Production Services accounted for 37.5%, 22.4%, 25.4% and 10.8%, respectively, of our total revenues, and the remainder of our revenues represented sales to five customers. For the year ended December 31, 2015, EOG Resources, US Well Services, Weatherford, and Archer Pressure Pumping accounted for 35.0%, 24.6%, 18.4% and 15.8%, respectively, of our total revenues, and the remainder of our revenues represented sales to three customers. Please read “Risk Factors—Risks Inherent in Our Business—A substantial majority of our revenues have been generated under contracts with a limited number of customers, and the loss of, material nonpayment or nonperformance by or significant reduction in purchases by any of them could adversely affect our business, results of operations and financial condition.” Beginning in the second quarter of 2018, we will have approximately 55.0% of our expanded annual nameplate production capacity of 5.5 million tons per year contracted with a volume-weighted average remaining term of approximately 2.4 years. For the years ended December 31, 2017, 2016 and 2015, we generated approximately 79.8%, 97.6% and 96.4%, respectively, of our revenues from raw frac sand delivered under long-term take-or-pay contracts. We sell raw frac sand under long-term contracts, as well as in the spot market if we have excess production and the spot market conditions are favorable.

Our current contracts include price ranges indexed to the price of crude oil (based upon the average WTI as listed on www.eia.doe.gov).  Our contracts contain provisions allowing for adjustment including: (i) annual percentage price escalators, or (ii) market factor increases (and in some cases decreases), including a natural gas surcharge/reduction and/or a propane surcharge/reduction which are applied if the Average Natural Gas Price or the Average Quarterly Mont Belvieu TX Propane Spot Price, respectively, as listed by the U.S. Energy Information Administration, are above or below the applicable benchmark set in the contract for the preceding calendar quarter.

Our contracts generally provide that, if we are unable to deliver the contracted minimum volume of raw frac sand, the customer has the right to purchase replacement raw frac sand from alternative sources, provided that our inability to supply is not the result of an excusable delay. In the event that the price of replacement raw frac sand exceeds the contract price and our inability to supply the contracted minimum volume is not the result of an excusable delay, we are responsible for the price difference, up to a specified limit. At December 31, 2017, we had significant levels of raw frac sand inventory on hand; therefore, we consider the likelihood of any such penalties as remote.

Certain of our contracts allow the customer to defer a portion of the annual minimum volume to future contract years, subject to a maximum deferral amount. The mesh size specifications in our contracts vary and include a mix of 20/40, 30/50, 40/70 and 100 mesh raw frac sand. In the event that one or more of our current contract customers decides not to continue purchasing our raw frac sand following the expiration of its contract with us, we believe that we will be able to sell the volume of sand that they previously purchased to other customers through long-term contracts or sales on the spot market.

Our Relationship with Our Sponsor

Our sponsor is a fund managed by Clearlake Capital Group, L.P., which, together with its affiliates and related persons, we refer to as Clearlake. Clearlake is a leading private investment firm founded in 2006. With a sector-focused approach, the firm seeks to partner with world-class management teams by providing patient, long-term capital to dynamic businesses that can benefit from Clearlake’s operational improvement approach, O.P.S.®. The firm’s core target sectors are industrials and energy; software, and technology-enabled services; and consumer. Clearlake has managed approximately $7 billion of institutional capital since inception and its senior investment principals have led or co-led over 100 investments. We believe our relationship with Clearlake provides us with a unique resource to effectively compete for acquisitions within the industry by being able to take advantage of their experience in acquiring businesses to assist us in seeking out, evaluating and closing attractive acquisition opportunities over time.

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Competition

The proppant industry is highly competitive. Please read “Risk Factors—Risks Inherent in Our Business—We face significant competition that may cause us to lose market share.” There are numerous large and small producers in all sand producing regions of the United States with whom we compete. Our main competitors include Badger Mining Corporation, Emerge Energy Services LP, Fairmount Santrol, Hi-Crush Partners LP, Unimin Corporation and U.S. Silica Holdings, Inc.

Although some of our competitors have greater financial and other resources than we do, we believe that we are competitively well positioned due to our low cost of production, transportation infrastructure and high-quality, balanced reserve profile. The most important factors on which we compete are product quality, performance, sand characteristics, transportation capabilities, reliability of supply and price. Demand for raw frac sand and the prices that we will be able to obtain for our products, to the extent not subject to a fixed price or take-or-pay contract, are closely linked to proppant consumption patterns for the completion of oil and natural gas wells in North America. These consumption patterns are influenced by numerous factors, including the price for hydrocarbons, the drilling rig count and hydraulic fracturing activity, including the number of stages completed and the amount of proppant used per stage. Further, these consumption patterns are also influenced by the location, quality, price and availability of raw frac sand and other types of proppants such as resin-coated sand and ceramic proppant.

Seasonality

Our business is affected to some extent by seasonal fluctuations in weather that impact the production levels at our wet processing plant. While our dry plants are able to process finished product volumes evenly throughout the year, our excavation and our wet sand processing activities have historically been limited to primarily non-winter months. As a consequence, we have experienced lower cash operating costs in the first and fourth quarter of each calendar year, and higher cash operating costs in the second and third quarter of each calendar year when we overproduced to meet demand in the winter months.  These higher cash operating costs were capitalized into inventory and expensed when these tons are sold, which can lead to us having higher overall production costs in the first and fourth quarters of each calendar year as we expense inventory costs that were previously capitalized. However, during the fourth quarter of 2017, we finished construction of our new, wet plant, which is an indoor facility that allows us to produce wet sand inventory year-round to support a portion of our dry sand processing capacity, which may reduce certain of the effects of this seasonality. We may also sell raw frac sand for use in oil and natural gas producing basins where severe weather conditions may curtail drilling activities and, as a result, our sales volumes to those areas may be reduced during such severe weather periods. For a discussion of the impact of weather on our operations, please read “Risk Factors—Seasonal and severe weather conditions could have a material adverse impact on our business, results of operations and financial condition” and “Risk Factors—Our cash flow fluctuates on a seasonal basis.”

Insurance

We believe that our insurance coverage is customary for the industry in which we operate and adequate for our business. As is customary in the proppant industry, we review our safety equipment and procedures and carry insurance against most, but not all, risks of our business. Losses and liabilities not covered by insurance would increase our costs. To address the hazards inherent in our business, we maintain insurance coverage that includes physical damage coverage, third-party general liability insurance, employer’s liability, business interruption, environmental and pollution and other coverage, although coverage for environmental and pollution-related losses is subject to significant limitations.

Environmental and Occupational Health and Safety Regulations

We are subject to stringent and complex federal, state and local laws and regulations governing the discharge of materials into the environment or otherwise relating to protection of worker health, safety and the environment. Compliance with these laws and regulations may expose us to significant costs and liabilities and cause us to incur significant capital expenditures in our operations. Any failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, imposition of remedial obligations, and the issuance of injunctions delaying or prohibiting operations. Private parties may also 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 damage. In addition, the trend in environmental regulation is to place more restrictions on activities that may affect the environment, and thus, any changes in, or more stringent enforcement of, these laws and regulations that result in more stringent and costly pollution control equipment, the occurrence of delays in the permitting or performance of projects, or waste handling, storage, transport, disposal or remediation requirements could have a material adverse effect on our operations and financial position.

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We do not believe that compliance by us with federal, state or local environmental laws and regulations will have a material adverse effect on our business, financial position or results of operations or cash flows. We cannot assure you, however, that future events, such as changes in existing laws or enforcement policies, the promulgation of new laws or regulations or the development or discovery of new facts or conditions adverse to our operations will not cause us to incur significant costs. The following is a discussion of material environmental and worker health and safety laws, as amended from time to time that relate to our operations or those of our customers that could have a material adverse effect on our business.

Air Emissions

Our operations are subject to the federal Clean Air Act (“CAA”) and related state and local laws, which restrict the emission of air pollutants and impose permitting, monitoring and reporting requirements on various sources. These regulatory programs may require us to install emissions abatement equipment, modify operational practices, and obtain permits for existing or new facilities or operations. Obtaining air emissions permits has the potential to delay the development or continued performance of our operations. Over the next several years, we may be required to incur certain capital expenditures for air pollution control equipment or to address other air emissions-related issues. Changing and increasingly stringent requirements, future non-compliance, or failure to maintain necessary permits or other authorizations could require us to incur substantial costs or suspend or terminate our operations.

Climate change

In recent years, the U.S. Congress has considered legislation to reduce emissions of greenhouse gases (“GHG”). It presently appears unlikely that comprehensive climate legislation will be passed by either house of Congress in the near future, although energy legislation and other regulatory initiatives are expected to be proposed that may be relevant to GHG emissions issues. In addition, a number of states are addressing GHG emissions, primarily through the development of emission inventories or regional GHG cap and trade programs. Depending on the particular program, we could be required to control GHG emissions or to purchase and surrender allowances for GHG emissions resulting from our operations. Independent of Congress, the U.S. Environmental Protection Agency (“EPA”) has adopted regulations controlling GHG emissions under its existing authority under the CAA. For example, following its findings that emissions of GHGs present an endangerment to human health and the environment because such emissions contributed to warming of the Earth’s atmosphere and other climatic changes, the EPA has adopted regulations under existing provisions of the CAA that, among other things, establish construction and operating permit reviews for GHG emissions from certain large stationary sources that are already potential major sources for conventional pollutants. The EPA also has adopted rules requiring the monitoring and reporting of GHG emissions from specified production, processing, transmission and storage facilities in the United States on an annual basis. In addition, in December 2015, over 190 countries, including the United States, reached an agreement to reduce global greenhouse gas emissions (the “Paris Agreement”).  The Paris Agreement entered into force in November 2016 after more than 170 nations, including the United States, ratified or otherwise indicated their intent to be bound by the agreement.  However, in June 2017, President Trump announced that the United States intends to withdraw from the Paris Agreement and to seek negotiations either to re-enter into the Paris Agreement on different terms or enter into a separate agreement.  In August 2017, the U.S. Department of State officially informed the United Nations of the United States’ intent 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.  To the extent that the United States and other countries implement this agreement or impose other climate change regulations on the oil and natural gas industry, it could have an adverse effect on our business because substantial limitations on GHG emissions could adversely affect demand for the oil and natural gas we produce. 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 and other climatic events; if any such effects were to occur, they could have an adverse effect on our mining and processing operations.

Water Discharges

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 other substances, into state waters or 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 requirements require containment to mitigate or prevent contamination of navigable waters in the event of an oil overflow, rupture or leak, and the development and maintenance of Spill Prevention Control and Countermeasure, or SPCC, plans at our facilities. The CWA and regulations implemented thereunder also prohibit the discharge of dredge and fill material into regulated waters, including jurisdictional wetlands, unless authorized by the Army Corps of Engineers (“Corps”) pursuant to an appropriately issued permit. 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 EPA has issued final rules attempting to clarify the federal jurisdictional reach over waters of the United States but this rule has been stayed nationwide by the U.S. Sixth Circuit Court of Appeals as that appellate court and numerous district courts ponder lawsuits opposing implementation of

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the rule. 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. Additionally, following the issuance of a presidential executive order to review the rule, the EPA and the Corps proposed a rulemaking to repeal the rule in June 2017. The EPA and the Corps also announced their intent to issue a new rule defining the Clean Water Act’s jurisdiction. In January 2018, the U.S. Supreme Court ruled that jurisdiction to hear challenges to the rule rests with the federal district courts.  Also in January 2018, the EPA and Corps issued a rule to delay the applicability of the rule for two years.  As a result, future implementation of the rule is uncertain at this time. To the extent this rule or a revised rule expands the scope of the Clean Water Act’s jurisdiction, we could face increased costs and delays with respect to obtaining permits for expansion activities. Federal and state regulatory agencies can impose administrative, civil and criminal penalties as well as other enforcement mechanisms for non-compliance with discharge permits or other requirements of the CWA and analogous state laws and regulations.

Hydraulic Fracturing

We supply raw frac sand to hydraulic fracturing operators in the oil and natural gas industry. Hydraulic fracturing is an important and increasingly common practice that is used to stimulate production of natural gas and oil from low permeability hydrocarbon bearing subsurface rock formations. The hydraulic fracturing process involves the injection of water, proppants, and chemicals under pressure into the formation to fracture the surrounding rock, increase permeability and stimulate production. Although we do not directly engage in hydraulic fracturing activities, our customers purchase our raw frac sand for use in their hydraulic fracturing activities. Hydraulic fracturing is typically regulated by state oil and natural gas commissions and similar agencies. Some states have adopted, and other states are considering adopting, regulations that could impose new or more stringent permitting, disclosure or well construction requirements on hydraulic fracturing operations. Aside from state laws, local land use restrictions may restrict drilling in general or hydraulic fracturing in particular. Municipalities may adopt local ordinances attempting to prohibit hydraulic fracturing altogether or, at a minimum, allow such fracturing processes within their jurisdictions to proceed but regulating the time, place and manner of those processes. In addition, federal agencies have started to assert regulatory authority over the process and various studies have been conducted or are currently underway by the EPA, and other federal agencies concerning the potential environmental impacts and, in some instances, have pursued voter ballot initiatives of hydraulic fracturing activities. At the same time, certain environmental groups have suggested that additional laws may be needed to more closely and uniformly limit or otherwise regulate the hydraulic fracturing process, and legislation has been proposed by some members of Congress to provide for such regulation.

The adoption of new laws or regulations at the federal or state levels imposing reporting obligations on, or otherwise limiting or delaying, the hydraulic fracturing process could make it more difficult to complete natural gas wells, increase our customers’ costs of compliance and doing business, and otherwise adversely affect the hydraulic fracturing services they perform, which could negatively impact demand for our raw frac sand. In addition, heightened political, regulatory, and public scrutiny of hydraulic fracturing practices could expose us or our customers to increased legal and regulatory proceedings, which could be time-consuming, costly, or result in substantial legal liability or significant reputational harm. We could be directly affected by adverse litigation involving us, or indirectly affected if the cost of compliance limits the ability of our customers to operate. Such costs and scrutiny could directly or indirectly, through reduced demand for our raw frac sand, have a material adverse effect on our business, financial condition and results of operations.

Non-Hazardous and Hazardous Wastes

The Resource Conservation and Recovery Act (“RCRA”) and comparable state laws control the management and disposal of hazardous and non-hazardous waste. These laws and regulations govern the generation, storage, treatment, transfer and disposal of wastes that we generate. In the course of our operations, we generate waste that are regulated as non-hazardous wastes and hazardous wastes, obligating us to comply with applicable standards relating to the management and disposal of such wastes. In addition, drilling fluids, produced waters, and most of the other wastes associated with the exploration, development, and production of oil or natural 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 natural gas drilling and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future. For example, in May 2016, several non-governmental environmental groups filed suit against the EPA in the U.S. District Court for the District of Columbia for failing to timely assess its RCRA Subtitle D criteria regulations for oil and natural gas wastes, asserting that the agency is required to review its Subtitle D regulations every three years but has not conducted an assessment on those oil and natural gas waste regulations since July 1988. The EPA and the non-governmental environmental groups entered into an agreement that was finalized in a consent decree issued by the U.S. District Court for the District of Columbia on December 28, 2016. Under the decree, the EPA is required to propose, by 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 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 customers’ costs to manage and dispose of generated wastes and a corresponding decrease in their drilling operations, which developments could have a material adverse effect on our business.

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Site Remediation

The Comprehensive Environmental Response, Compensation, and Liability Act, as amended (“CERCLA”) and comparable state laws impose strict, joint and several liability without regard to fault or the legality of the original conduct on certain classes of persons that contributed to the release of a hazardous substance into the environment. These persons include the owner and operator of a disposal site where a hazardous substance release occurred and any company that transported, disposed of, or arranged for the transport or disposal of hazardous substances released at the site. Under CERCLA, such persons may be liable for the costs of remediating the hazardous substances that have been released into the environment, for damages to natural resources, and for the costs of certain health studies. In addition, where contamination may be present, it is not uncommon for the neighboring landowners and other third parties to file claims for personal injury, property damage and recovery of response costs. We have not received notification that we may be potentially responsible for cleanup costs under CERCLA at any site.

Endangered Species

The Endangered Species Act (“ESA”) restricts activities that may affect endangered or threatened species or their habitats. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. As a result of a settlement approved by the U.S. District Court for the District of Columbia in 2011, the U.S. Fish and Wildlife Service (“FWS”) was required to consider listing numerous species as endangered or threatened under the Endangered Species Act before the completion of the agency’s 2017 fiscal year. The FWS did not meet the deadline. Current ESA listings and the designation of previously unprotected species as threatened or endangered in areas where we or our customers operate could cause us or our customers to incur increased costs arising from species protection measures and could result in delays or limitations in our or our customers’ performance of operations, which could adversely affect or reduce demand for our raw frac sand. For example, the dunes sagebrush lizard, which is found only in the active and semi-stable shinnery oak dunes of southeastern New Mexico and adjacent portions of Texas, was a candidate species for listing under the ESA by the FWS for many years.  In 2010, the FWS proposed listing the dunes sagebrush lizard as an endangered species under the ESA.  In response, the Texas Comptroller’s Office created the TCP in 2012 to minimize disturbances to the dunes sagebrush lizard’s habitat.  In June 2012, the FWS declined to list the species as endangered under the ESA.  Recently, however, as a result of increased frac sand mining, the Texas Comptroller’s Office, FWS and environmental groups have voiced concerns about the potential destruction of dunes sagebrush lizard habitat and harm to the species, which could ultimately lead to renewed calls to FWS to list the dunes sagebrush lizard under the ESA.

Mining and Workplace Safety

Our sand mining operations are subject to mining safety regulation. The U.S. Mining Safety and Health Administration (“MSHA”) is the primary regulatory organization governing raw frac sand mining and processing. Accordingly, MSHA regulates quarries, surface mines, underground mines and the industrial mineral processing facilities associated with and located at quarries and mines. The mission of MSHA is to administer the provisions of the Federal Mine Safety and Health Act of 1977 and to enforce compliance with mandatory miner safety and health standards. As part of MSHA’s oversight, representatives perform at least two unannounced inspections annually for each above-ground facility.

OSHA has promulgated new rules for workplace exposure to respirable silica for several other industries. Respirable silica is a known health hazard for workers exposed over long periods. MSHA is expected to adopt similar rules as part of its “Long Term Items” for rulemaking. Airborne respirable silica is associated with work areas at our site and is monitored closely through routine testing and MSHA inspection. If the workplace exposure limit is lowered significantly, we may be required to incur certain capital expenditures for equipment to reduce this exposure. Smart Sand also adheres to the NISA’s respiratory protection program, and ensures that workers are provided with fitted respirators and ongoing radiological monitoring.

Environmental Reviews

Our operations may be subject to broad environmental review under the National Environmental Policy Act, as amended, (“NEPA”). NEPA requires federal agencies to evaluate the environmental impact of all “major federal actions” significantly affecting the quality of the human environment. The granting of a federal permit for a major development project, such as a mining operation, may be considered a “major federal action” that requires review under NEPA. As part of this evaluation, the federal agency considers a broad array of environmental impacts, including, among other things, impacts on air quality, water quality, wildlife (including threatened and endangered species), historic and archeological resources, geology, socioeconomics, and aesthetics. NEPA also requires the consideration of alternatives to the project. The NEPA review process, especially the preparation of a full environmental impact statement, can be time consuming and expensive. The purpose of the NEPA review process is to inform federal agencies’ decision-making on whether federal approval should be granted for a project and to provide the public with an opportunity to comment on the environmental impacts of a proposed project. Though NEPA requires only that an environmental evaluation be conducted and does not mandate a particular result, a federal agency could decide to deny a permit or impose certain conditions on its approval, based on its environmental review under NEPA, or a third party could challenge the adequacy of a NEPA review and thereby delay the issuance of a federal permit or approval.

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State and Local Regulation

We are subject to a variety of state and local environmental review and permitting requirements. Some states, including Wisconsin where our current projects are located, have state laws similar to NEPA; thus, our development of a new site or the expansion of an existing site may be subject to comprehensive state environmental reviews even if it is not subject to NEPA. In some cases, the state environmental review may be more stringent than the federal review. Our operations may require state-law based permits in addition to federal permits, requiring state agencies to consider a range of issues, many the same as federal agencies, including, among other things, a project’s impact on wildlife and their habitats, historic and archaeological sites, aesthetics, agricultural operations, and scenic areas. Wisconsin has specific permitting and review processes for commercial silica mining operations, and state agencies may impose different or additional monitoring or mitigation requirements than federal agencies. The development of new sites and our existing operations also are subject to a variety of local environmental and regulatory requirements, including land use, zoning, building, and transportation requirements.

Demand for raw frac sand in the oil and natural gas industry drove a significant increase in the production of frac sand. As a result, some local communities expressed concern regarding silica sand mining operations. These concerns have generally included exposure to ambient silica sand dust, truck traffic, water usage and blasting. In response, certain state and local communities have developed or are in the process of developing regulations or zoning restrictions intended to minimize dust from becoming airborne, control the flow of truck traffic, significantly curtail the amount of practicable area for mining activities, provide compensation to local residents for potential impacts of mining activities and, in some cases, ban issuance of new permits for mining activities. To date, we have not experienced any material impact to our existing mining operations or planned capacity expansions as a result of these types of concerns. We would expect this trend to continue as oil and natural gas production increases.

In August 2014, we were accepted as a “Tier 1” participant in Wisconsin’s voluntary “Green Tier” program, which encourages, recognizes and rewards companies for voluntarily exceeding environmental, health and safety legal requirements. Successful Tier 1 participants are required to demonstrate a strong record of environmental compliance, develop and implement an environmental management system meeting certain criteria, conduct and submit annual performance reviews to the Wisconsin Department of Natural Resources, promptly correct any findings of non-compliance discovered during these annual performance reviews, and make certain commitments regarding future environmental program improvements. Our most recent annual report required under the Tier 1 protocol was submitted to the Green Tier Program contact on August 1, 2017.

Employees

As of December 31, 2017, we employed 198 people. None of our employees are subject to collective bargaining agreements. We consider our employee relations to be good.

Executive Officers of the Registrant

Charles E. Young

Charles E. Young was named Chief Executive Officer in July 2014. Mr. Young has also served as a director since September 2011. Mr. Young founded Smart Sand, LLC (our predecessor) and served as its President from November 2009 to August 2011. Mr. Young served as our President and Secretary from September 2011 to July 2014. Mr. Young has over 20 years of executive and entrepreneurial experience in the high-technology, telecommunications and renewable energy industries. He previously served as the President and Founder of Premier Building Systems, a construction, solar, geothermal and energy audit company in Pennsylvania and New Jersey from 2006 to 2011. Mr. Young serves as a director for Gravity Oilfield Services, Inc., a privately-held company. Mr. Young received a B.A. in Political Science from Miami University. Mr. Young is the brother of William John Young, our Executive Vice President of Sales and Logistics, and James D. Young, our Executive Vice President, General Counsel and Secretary. We believe that Mr. Young’s industry experience and deep knowledge of our business makes him well suited to serve as Chief Executive Officer and Director.

Lee E. Beckelman

Lee E. Beckelman was named Chief Financial Officer in August 2014. From December 2009 to February 2014, Mr. Beckelman served as Executive Vice President and Chief Financial Officer of Hilcorp Energy Company, an exploration and production company. From February 2008 to October 2009, he served as the Executive Vice President and Chief Financial Officer of Price Gregory Services, Incorporated, a crude oil and natural gas pipeline construction firm until its sale to Quanta Services. Prior thereto, Mr. Beckelman served in various roles from 2002 to 2007 at Hanover Compressor Company, an international oil field service company, until its merger with Universal Compression to form Exterran Holdings. Mr. Beckelman received his BBA in Finance with High Honors from the University of Texas at Austin.

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Robert Kiszka

Robert Kiszka was named Executive Vice President of Operations in May 2014. Mr. Kiszka has served as the Vice President of Operations since September 2011. Mr. Kiszka has over 20 years of construction, real estate, renewable energy and mining experience. Mr. Kiszka has been the owner of A-1 Bracket Group Inc. since 2005 and was a member of Premier Building Systems LLC from 2010 to 2011. Mr. Kiszka attended Pedagogical University in Krakow, Poland and Rutgers University.

Ronald P. Whelan

Ronald P. Whelan was named Executive Vice President of Business Development in April 2017. Prior to that time, he served as Vice President of Business Development from September 2016 to March 2017 and as Director of Business Development from April 2014 to August 2016. Prior to being named Director of Business Development, Mr. Whelan was the Operations Manager responsible for the design, development and production of the Oakdale facility from November 2011 to April 2014. Before joining Smart Sand, Mr. Whelan ran his own software design company from 2004 to 2011 and was a member of Premier Building Systems LLC from 2008 to 2009. Mr. Whelan has over 15 years of entrepreneurial experience in mining, technology and renewable energy industries. Mr. Whelan received a B.A. in Marketing from Bloomsburg University and M.S. in Instructional Technology from Bloomsburg University.

James D. Young

James D. Young was named Executive Vice President, General Counsel and Secretary in June 2017.  Prior to joining us, Mr. Young was a partner of the law firm Fox Rothschild LLP, where he worked for thirteen years and served as our outside general counsel.  Mr. Young received a J.D. from Rutgers University School of Law and his B.A. in History and Political Science from the University of Toronto.  Mr. Young is the brother of Charles Young, our Chief Executive Officer and member of our board of directors, and William John Young, our Executive Vice President of Sales and Logistics.

William John Young

William John Young was named Executive Vice President of Sales and Logistics in October 2016. Mr. Young served as Vice President of Sales and Logistics from May 2014 to September 2016 and Director of Sales from November 2011 to April 2014. Prior to joining us, Mr. Young was a Director of Sales for Comcast Corporation from 2002 to 2011. Mr. Young brings over 20 years of experience in the mining, commercial telecommunications and broadband industries. Mr. Young received a BSc in Biology from Dalhousie University. Mr. Young is the brother of Charles E. Young, our Chief Executive Officer and member of our board of directors, and James D. Young, our Executive Vice President, General Counsel and Secretary.

Susan Neumann

Susan Neumann was named Vice President of Accounting, Controller and Secretary in October 2016. Previously, Ms. Neumann was named Controller and Secretary in April 2013 and July 2014, respectively. Prior to joining us in April 2013, Ms. Neumann was an assurance senior manager at BDO USA, LLP (“BDO”). At BDO, she served in various roles in the assurance group from September 2000 to March 2013. Ms. Neumann received an MBA with a Global Perspective from Arcadia University and a B.A. in Accounting from Beaver College (currently Arcadia University).

Available Information

Our website address is www.smartsand.com. Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports are available on our website, without charge, as soon as reasonably practicable after they are filed electronically with the SEC. The public may read and copy any materials we file with the SEC at its Public Reference Room at 100 F. Street, NE, Washington, DC 20549. Information on the operation of the Public Reference Room may be obtained by calling the SEC at 1-800-SEC-0330. The SEC also maintains a website that contains reports, proxy and information statements and other information statements and other information regarding issuers who file electronically with the SEC. The SEC’s website address is www.sec.gov.

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Item 1A. – Risk Factors

Risks Inherent in Our Business

Our business and financial performance depend on the level of activity in the oil and natural gas industry.

Substantially all of our revenues are derived from sales to companies in the oil and natural gas industry. As a result, our operations are dependent on the levels of activity in oil and natural gas exploration, development and production. More specifically, the demand for the proppants we produce is closely related to the number of oil and natural gas wells completed in geological formations where sand-based proppants are used in fracturing activities. These activity levels are affected by both short- and long-term trends in oil and natural gas prices, among other factors.

Oil and natural gas prices and, therefore, the level of exploration, development and production activity, have experienced a high level of volatility leading to sustained declines from the highs in the latter half of 2014 that continued through early 2016. Beginning in September 2014 and continuing through early 2016, increasing global supply of oil, including a decision by the Organization of the Petroleum Exporting Countries (“OPEC”) to sustain its production levels in spite of the decline in oil prices, in conjunction with weakened demand from slowing economic growth in the Eurozone and China, created downward pressure on crude oil prices resulting in reduced demand for our products and pressure to reduce our product prices. In November and December 2016, OPEC and non-OPEC producers reached a curtailment agreement to curb output for the first six months of 2017, which led to less oil price volatility and increased drilling and well completion activity beginning late in 2016 and continuing into 2017. In November 2017, the curtailment agreement was upheld which has led to continued drilling activity into early 2018.  However, should the curtailment agreement not be maintained or other sources of production continue to rise at levels not supported by current demand, these factors could lead to lower oil prices and reduced drilling and well completion activity which could adversely impact our operations. Furthermore, the availability of key resources that impact drilling activity has significantly fluctuated recently, which could impact product demand.

A prolonged reduction in oil and natural gas prices would generally depress the level of oil and natural gas exploration, development, production and well completion activity and would result in a corresponding decline in the demand for the proppants we produce. Such a decline would have a material adverse effect on our business, results of operation and financial condition. The commercial development of economically viable alternative energy sources (such as wind, solar, geothermal, tidal, fuel cells and biofuels) could have a similar effect. In addition, certain U.S. federal income tax deductions currently available with respect to oil and natural gas exploration and development, including the repeal of the percentage depletion allowance for oil and natural gas properties, may be eliminated as a result of proposed legislation. Any future decreases in the rate at which oil and natural gas reserves are discovered or developed, whether due to the passage of legislation, increased governmental regulation leading to limitations, or prohibitions on exploration and drilling activity, including hydraulic fracturing, or other factors, could have a material adverse effect on our business and financial condition, even in a stronger oil and natural gas price environment.

The recently passed comprehensive tax reform bill could adversely affect our business and financial condition.

On December 22, 2017, the U.S. Tax Cuts and Jobs Act (the “Tax Reform Act”) was signed into law. The Tax Reform Act significantly revised the U.S. corporate income tax regime by, among other things, lowering the U.S. corporate tax rate from 35% to 21% effective January 1, 2018, repealing the deduction for domestic production activities, implementing 100% direct expensing of certain non-residential property, partially limiting the deductibility of business interest expense, limiting the deduction for certain net operating losses to 80% of current year taxable income, providing for an indefinite carryforward of certain net operating losses and modifying or repealing many business deductions and credits. We continue to examine the impact of this tax reform legislation, and as its overall impact is uncertain, we note that the Tax Reform Act could adversely affect our business and financial condition. The impact of this tax reform legislation on holders of our common stock is also uncertain and could be adverse.

We previously had difficulty maintaining compliance with the covenants and ratios required under our former revolving credit facility. We may have similar difficulties with our current revolving credit facility. Failure to maintain compliance with these financial covenants or ratios could adversely affect our business, financial condition, results of operations and cash flows.

We have historically relied on our former revolving credit facility, which was paid in full and terminated using the proceeds of our initial public offering (“IPO”) in November 2016, and expect to rely on our current revolving credit facility to provide liquidity and support for our growth objectives, as necessary. Our revolving credit facility requires us to comply with certain financial covenants and ratios. Our ability to comply with these restrictions and covenants in the future is uncertain and will be affected by the levels of cash flow from our operations and events or circumstances beyond our control, including events and circumstances that may stem from the condition of financial markets and commodity price levels. At December 31, 2017 we were in compliance with the covenants contained in our existing revolving credit facility.

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In the event that we are unable to access sufficient capital to fund our business and planned capital expenditures, we may be required to curtail potential acquisitions, strategic growth projects, portions of our current operations and other activities. A lack of capital could result in a decrease in our operations, subject us to claims of breach under customer and supplier contracts and may force us to sell some of our assets or issue additional equity on an untimely or unfavorable basis, each of which could adversely affect our business, financial condition, results of operations and cash flows.

A substantial majority of our revenues have been generated under contracts with a limited number of customers, and the loss of, material nonpayment or nonperformance by or significant reduction in purchases by any of them could adversely affect our business, results of operations and financial condition.

As of January 1, 2018, we were contracted to sell raw frac sand produced from our Oakdale facility under six long-term take-or-pay contracts with a weighted average remaining life of approximately 2.4 years. Because we have a small number of customers contracted under long-term take-or-pay contracts, these contracts subject us to counterparty risk. The ability or willingness of each of our customers to perform its obligations under a contract with us will depend on a number of factors that are beyond our control and may include, among other things, the overall financial condition of the counterparty, the condition of the U.S. oil and natural gas exploration and production industry, continuing use of raw frac sand in hydraulic fracturing operations and general economic conditions. In addition, in depressed market conditions, our customers may no longer need the amount of raw frac sand for which they have contracted or may be able to obtain comparable products at a lower price. If our customers experience a significant downturn in their business or financial condition, they may attempt to renegotiate our contracts. For example, a number of our existing contracts were adjusted in 2015 and early 2016 resulting in a combination of reduced average selling prices per ton, adjustments to take-or-pay volumes and length of contract. While we added two new contracts in 2017, customers increased their purchases of volumes on a spot basis and we expect this trend to continue until customers are more comfortable in the sustainability of current oil and natural gas drilling activity. If any of our major customers substantially reduces or altogether ceases purchasing our raw frac sand and we are not able to generate replacement sales of raw frac sand into the market, our business, financial condition and results of operations could be adversely affected until such time as we generate replacement sales in the market. In addition, as contracts expire, depending on market conditions at the time, our customers may choose not to extend these contracts which could lead to a significant reduction of sales volumes and corresponding revenues cash flows and financial condition if we are not able to replace these contracts with new sales volumes. For example, we had one contract of 1.1 million tons per year that expired in November 2016, and this contract was not renewed beyond its contractual term. Additionally, even if we were to replace any lost contract volumes, lower prices for our product could materially reduce our revenues, cash flow and financial condition.

We are exposed to the credit risk of our customers, and any material nonpayment or nonperformance by our customers could adversely affect our business, results of operations and financial condition.

We are subject to the risk of loss resulting from nonpayment or nonperformance by our customers. Our credit procedures and policies may not be adequate to fully eliminate customer credit risk. If we fail to adequately assess the creditworthiness of existing or future customers or unanticipated deterioration in their creditworthiness, any resulting increase in nonpayment or nonperformance by them and our inability to re-market or otherwise use the production could have a material adverse effect on our business, results of operations and financial condition. A decline in natural gas and crude oil prices could negatively impact the financial condition of our customers and sustained lower prices could impact their ability to meet their financial obligations to us. Further, our contract counterparties may not perform or adhere to our existing or future contractual arrangements. To the extent one or more of our contract counterparties is in financial distress or commences bankruptcy proceedings, contracts with these counterparties may be subject to renegotiation or rejection under applicable provisions of the United States Bankruptcy Code. Any material nonpayment or nonperformance by our contract counterparties due to inability or unwillingness to perform or adhere to contractual arrangements could adversely affect our business and results of operations.

Our proppant sales are subject to fluctuations in market pricing.

A majority of our supply agreements involving the sale of raw frac sand have market-based pricing mechanisms. Accordingly, in periods with decreasing prices, our results of operations may be lower than if our agreements had fixed prices. During these periods our customers may also elect to reduce their purchases from us and seek to find alternative, cheaper sources of supply. In periods with increasing prices, these agreements permit us to increase prices; however, these increases are generally calculated on a quarterly basis and do not increase on a dollar-for-dollar basis with increases in spot market pricing. Furthermore, certain volume-based supply agreements may influence the ability to fully capture current market pricing. These pricing provisions may result in significant variability in our results of operations and cash flows from period to period.

Changes in supply and demand dynamics could also impact market pricing for proppants. A number of existing proppant providers and new market entrants have recently announced reserve acquisitions, processing capacity expansions and greenfield projects. In periods where sources of supply of raw frac sand exceed market demand, market prices for raw frac sand may decline and

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our results of operations and cash flows may continue to decline, be volatile, or otherwise be adversely affected. For example, beginning in September 2014 and continuing through 2016, increasing global supply of oil, in conjunction with weakened demand from slowing economic growth in the Eurozone and China, created downward pressure on crude oil prices resulting in reduced demand for hydraulic fracturing services leading to a corresponding reduced demand for our products and pressure to reduce our product prices.

We face significant competition that may cause us to lose market share.

The proppant industry is highly competitive. The proppant market is characterized by a small number of large, national producers and a larger number of small, regional or local producers. Competition in this industry is based on price, consistency and quality of product, site location, distribution capability, customer service, reliability of supply, breadth of product offering and technical support.

Some of our competitors have greater financial and other resources than we do. In addition, our larger competitors may develop technology superior to ours or may have production facilities that offer lower-cost transportation to certain customer locations than we do. When the demand for hydraulic fracturing services decreases or the supply of proppant available in the market increases, prices in the raw frac sand market can materially decrease. Furthermore, oil and natural gas exploration and production companies and other providers of hydraulic fracturing services have acquired and in the future may acquire their own raw frac sand reserves to fulfill their proppant requirements, and these other market participants may expand their existing raw frac sand production capacity, all of which would negatively impact demand for our raw frac sand. In addition, increased competition in the proppant industry could have an adverse impact on our ability to enter into long-term contracts or to enter into contracts on favorable terms. For example, new supplies of regional raw frac sand from our competitors are scheduled to come online in 2018, primarily in the Permian Basin of West Texas.  Depending on the overall market for raw frac sand, these supplies could have a negative impact our ability to market our Northern White Sand in the Permian Basin or other markets in close proximity to these new mines or could lead to pressure to reduce prices to compete effectively with these new regional suppliers.

We may be required to make substantial capital expenditures to maintain, develop and increase our asset base. The inability to obtain needed capital or financing on satisfactory terms, or at all, could have an adverse effect on our business, results of operations and financial condition.

Although we currently use a significant amount of our cash generated from our operations to fund the maintenance and development of our asset base, we may depend on the availability of credit to fund future capital expenditures. Our ability to obtain bank financing or to access the capital markets for future equity or debt offerings may be limited by our financial condition at the time of any such financing or offering, the covenants contained in the new revolving credit facility or other future debt agreements, adverse market conditions or other contingencies and uncertainties that are beyond our control. Our failure to obtain the funds necessary to maintain, develop and increase our asset base could adversely impact our business, results of operations and financial condition.

Even if we are able to obtain financing or access the capital markets, incurring additional debt may significantly increase our interest expense and financial leverage, and our level of indebtedness could restrict our ability to fund future development and acquisition activities. In addition, the issuance of additional equity interests may result in significant dilution to our existing common stockholders.

Inaccuracies in estimates of volumes and qualities of our sand reserves could result in lower than expected sales and higher than expected production costs.

John T. Boyd, our independent reserve engineers, prepared estimates of our reserves based on engineering, economic and geological data assembled and analyzed by our engineers and geologists. However, raw frac sand reserve estimates are by nature imprecise and depend to some extent on statistical inferences drawn from available data, which may prove unreliable. There are numerous uncertainties inherent in estimating quantities and qualities of reserves and non-reserve raw frac sand deposits and costs to mine recoverable reserves, including many factors beyond our control. Estimates of economically recoverable raw frac sand reserves necessarily depend on a number of factors and assumptions, all of which may vary considerably from actual results, such as:

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Any inaccuracy in John T. Boyd’s estimates related to our raw frac sand reserves or non-reserve raw frac sand deposits could result in lower than expected sales or higher than expected costs. For example, John T. Boyd’s estimates of our proven recoverable sand reserves assume that our revenue and cost structure will remain relatively constant over the life of our reserves. If these assumptions prove to be inaccurate, some or all of our reserves may not be economically mineable, which could have a material adverse effect on our results of operations and cash flows. In addition, our current customer contracts require us to deliver raw frac sand that meets certain API and ISO specifications. If John T. Boyd’s estimates of the quality of our reserves, including the volumes of the various specifications of those reserves, prove to be inaccurate, we may incur significantly higher excavation costs without corresponding increases in revenues, we may not be able to meet our contractual obligations, or our facilities may have a shorter than expected reserve life, any of which could have a material adverse effect on our results of operations and cash flows.

All of our sales are generated at one facility, and that facility is primarily served by one rail line. Any adverse developments at that facility or on the rail line could have a material adverse effect on our business, financial condition and results of operations.

All of our sales are currently derived from our Oakdale facility located in Oakdale, Wisconsin, which is served primarily by a Class I rail line owned by Canadian Pacific. Any adverse development at this facility or on the rail line due to catastrophic events or weather, or any other event that would cause us to curtail, suspend or terminate operations at our Oakdale facility, could result in us being unable to meet our contracted sand deliveries. Although we have access to a second Class I rail line owned by Union Pacific at our Byron facility, we could not facilitate all shipments of product from the Byron facility. We maintain insurance coverage to cover a portion of these types of risks; however, there are potential risks associated with our operations not covered by insurance. There also may be certain risks covered by insurance where the policy does not reimburse us for all of the costs related to a loss. Downtime or other delays or interruptions to our operations that are not covered by insurance could have a material adverse effect on our business, results of operations and financial condition. In addition, under our long-term take-or-pay contracts, if we are unable to deliver contracted volumes and a customer arranges for delivery from a third party at a higher price, we may be required to pay that customer the difference between our contract price and the price of the third-party product.

If we are unable to make acquisitions on economically acceptable terms, our future growth would be limited.

A portion of our strategy to grow our business is dependent on our ability to make acquisitions. If we are unable to make acquisitions from third parties because we are unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts, we are unable to obtain financing for these acquisitions on economically acceptable terms or we are outbid by competitors, our future growth may be limited. Any acquisition involves potential risks, some of which are beyond our control, including, among other things:

If we consummate any future acquisitions, our capitalization and results of operations may change significantly, and common stockholders will not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in determining the application of these funds and other resources.

We may not be able to complete greenfield development or expansion projects or, if we do, we may not realize the expected benefits.

Any greenfield development or expansion project requires us to raise substantial capital and obtain numerous state and local permits. A decision by any governmental agency not to issue a required permit or substantial delays in the permitting process could prevent us from pursuing the development or expansion project. In addition, if the demand for our products declines during a period in

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which we experience delays in raising capital or completing the permitting process, we may not realize the expected benefits from our greenfield facility or expansion project. Furthermore, our new or modified facilities may not operate at designed capacity or may cost more to operate than we expect. The inability to complete greenfield development or expansion projects or to complete them on a timely basis and in turn grow our business could adversely affect our business and results of operations.

Restrictions in our revolving credit facility may limit our ability to capitalize on potential acquisition and other business opportunities.

The operating and financial restrictions and covenants in our revolving credit facility and any future financing agreements could restrict our ability to finance future operations or capital needs or to expand or pursue our business activities. For example, our revolving credit facility restricts or limits our ability to:

Furthermore, our revolving credit facility contains certain operating and financial covenants. Our ability to comply with such covenants and restrictions contained in our credit facility may be affected by events beyond our control, including prevailing economic, financial and industry conditions. If market or other economic conditions deteriorate, our ability to comply with these covenants may be impaired. If we violate any of the restrictions, covenants, ratios or tests in the new revolving credit facility, a significant portion of our indebtedness may become immediately due and payable, and any lenders’ commitment to make further loans to us may terminate. We might not have, or be able to obtain, sufficient funds to make these accelerated payments. Any subsequent replacement of the new revolving credit facility or any new indebtedness could have similar or greater restrictions. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Credit Facilities—Our Credit Facility and Other Arrangements.”

We face distribution and logistical challenges in our business.

Transportation and logistical operating expenses comprise a significant portion of the costs incurred by our customers to deliver raw frac sand to the wellhead, which could favor suppliers located in close proximity to the customer. As oil and natural gas prices fluctuate, our customers may shift their focus to different resource plays, some of which may be located in geographic areas that do not have well-developed transportation and distribution infrastructure systems, or seek contracts with additional delivery and pricing alternatives including contracts that sell product on an “as-delivered” basis at the target shale basin. Serving our customers in these less-developed areas presents distribution and other operational challenges that may affect our sales and negatively impact our operating costs and any delays we experience in optimizing our logistics infrastructure or developing additional origination and destination points may adversely affect our ability to renew existing contracts with customers seeking additional delivery and pricing alternatives. Disruptions in transportation services, including shortages of railcars, lack of developed infrastructure, weather-related problems, flooding, drought, accidents, mechanical difficulties, strikes, lockouts, bottlenecks or other events could affect our ability to timely and cost effectively deliver to our customers and could temporarily impair the ability of our customers to take delivery and, in certain circumstances, constitute a force majeure event under our customer contracts, permitting our customers to suspend taking delivery of and paying for our raw frac sand. Additionally, increases in the price of transportation costs, including freight charges, fuel surcharges, transloading fees, terminal switch fees and demurrage costs, could negatively impact operating costs if we are unable to pass those increased costs along to our customers. Accordingly, because we are so dependent on rail infrastructure, if there are disruptions of the rail transportation services utilized by us or our customers, and we or our customers are unable to find alternative transportation providers to transport our products, our business and results of operations could be adversely affected. Further, declining volumes could result in railcar over-capacity, which would lead to railcar storage fees while, at the same time, we would continue to incur lease costs for those railcars in storage. Failure to find long-term solutions to these logistical challenges could adversely affect our ability to respond quickly to the needs of our customers or result in additional increased costs, and thus could negatively impact our business, results of operations and financial condition.

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We may be adversely affected by decreased demand for raw frac sand due to the development of effective alternative proppants or new processes to replace hydraulic fracturing.

Raw frac sand is a proppant used in the completion and re-completion of oil and natural gas wells to stimulate and maintain oil and natural gas production through the process of hydraulic fracturing. Raw frac sand is the most commonly used proppant and is less expensive than other proppants, such as resin-coated sand and manufactured ceramics. A significant shift in demand from raw frac sand to other proppants, or the development of new processes to make hydraulic fracturing more efficient could replace it altogether, could cause a decline in the demand for the raw frac sand we produce and result in a material adverse effect on our business, results of operations and financial condition.

An increase in the supply of raw frac sand having similar characteristics as the raw frac sand we produce could make it more difficult for us to renew or replace our existing contracts on favorable terms, or at all.

If significant new reserves of raw frac sand are discovered and developed, and those raw frac sands have similar characteristics to the raw frac sand we produce, we may be unable to renew or replace our existing contracts on favorable terms, or at all. Specifically, if high-quality raw frac sand becomes more readily available, our customers may not be willing to enter into long-term take-or-pay contracts, may demand lower prices or both, which could have a material adverse effect on our business, results of operations and financial condition. For example, new supplies of regional raw frac sand from our competitors are scheduled to come online in 2018, primarily in the Permian Basin of West Texas. Depending on the overall market for raw frac sand, these supplies could have a negative impact our ability to market our Northern White Sand in the Permian Basin or other markets in close proximity to these new mines or could lead to pressure to reduce prices to compete effectively with these new regional suppliers.

Federal, state and local legislative and regulatory initiatives relating to hydraulic fracturing and the potential for related litigation could result in increased costs, additional operating restrictions or delays for our customers, which could cause a decline in the demand for our raw frac sand and negatively impact our business, results of operations and financial condition.

We supply raw frac sand to hydraulic fracturing operators in the oil and natural gas industry. Hydraulic fracturing is an important practice that is used to stimulate production of natural gas and oil from low permeability hydrocarbon bearing subsurface rock formations. The hydraulic fracturing process involves the injection of water, proppants, and chemicals under pressure into the formation to fracture the surrounding rock, increase permeability and stimulate production.

Although we do not directly engage in hydraulic fracturing activities, our customers purchase our raw frac sand for use in their hydraulic fracturing activities. Hydraulic fracturing is typically regulated by state oil and natural gas commissions and similar agencies. Some states have adopted, and other states are considering adopting, regulations that could impose new or more stringent permitting, disclosure or well construction requirements on hydraulic fracturing operations. Aside from state laws, local land use restrictions may restrict drilling in general or hydraulic fracturing in particular. Municipalities may adopt local ordinances attempting to prohibit hydraulic fracturing altogether or, at a minimum, allow such fracturing processes within their jurisdictions to proceed but regulating the time, place and manner of those processes. In addition, federal agencies have started to assert regulatory authority over the process and various studies have been conducted or are currently underway by the EPA, and other federal agencies concerning the potential environmental impacts of hydraulic fracturing activities. At the same time, certain environmental groups have suggested that additional laws may be needed and, in some instances, have pursued voter ballot initiatives to more closely and uniformly limit or otherwise regulate the hydraulic fracturing process, and legislation has been proposed by some members of Congress to provide for such regulation.

The adoption of new laws or regulations at the federal, state or local levels imposing reporting obligations on, or otherwise limiting or delaying, the hydraulic fracturing process could make it more difficult to complete natural gas wells, increase our customers’ costs of compliance and doing business, and otherwise adversely affect the hydraulic fracturing services they perform, which could negatively impact demand for our raw frac sand. In addition, heightened political, regulatory, and public scrutiny of hydraulic fracturing practices could expose us or our customers to increased legal and regulatory proceedings, which could be time-consuming, costly, or result in substantial legal liability or significant reputational harm. We could be directly affected by adverse litigation involving us, or indirectly affected if the cost of compliance limits the ability of our customers to operate. Such costs and scrutiny could directly or indirectly, through reduced demand for our raw frac sand, have a material adverse effect on our business, financial condition and results of operations.

Our long-term take-or-pay contracts may preclude us from taking advantage of increasing prices for raw frac sand or mitigating the effect of increased operational costs during the term of those contracts.

The long-term take-or-pay contracts we have may negatively impact our results of operations. Our long-term take-or-pay contracts require our customers to pay a specified price for a specified volume of raw frac sand each month. Although our long-term take-or-pay contracts provide for price increases based on crude oil prices, such increases are generally calculated on a quarterly basis and do not increase dollar-for-dollar with increases in spot market prices. As a result, in periods with increasing prices our sales may not keep pace with market prices.

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Additionally, if our operational costs increase during the terms of our long-term take-or-pay contracts, we will not be able to pass some of those increased costs to our customers. If we are unable to otherwise mitigate those increased operational costs, our net income could decline.

Our operations are subject to operational hazards and unforeseen interruptions for which we may not be adequately insured.

Our operations are exposed to potential natural disasters, including blizzards, tornadoes, storms, floods, other adverse weather conditions and earthquakes. If any of these events were to occur, we could incur substantial losses because of personal injury or loss of life, severe damage to and destruction of property and equipment, and pollution or other environmental damage resulting in curtailment or suspension of our operations.

We are not fully insured against all risks incident to our business, including the risk of our operations being interrupted due to severe weather and natural disasters. Furthermore, we may be unable to maintain or obtain insurance of the type and amount we desire at reasonable rates. As a result of market conditions, premiums and deductibles for certain of our insurance policies have increased and could escalate further. In addition, sub-limits have been imposed for certain risks. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage. If we were to incur a significant liability for which we are not fully insured, it could have a material adverse effect on our business, results of operations and financial condition.

Our production process consumes large amounts of natural gas and electricity. An increase in the price or a significant interruption in the supply of these or any other energy sources could have a material adverse effect on our business, results of operations and financial condition.

Energy costs, primarily natural gas and electricity, represented approximately 5.8% of our total cost of goods sold for the year ended December 31, 2017. Natural gas is currently the primary fuel source used for drying in our raw frac sand production process. As a result, our profitability will be impacted by the price and availability of natural gas we purchase from third parties. Because we have not contracted for the provision of natural gas on a fixed-price basis, our costs and profitability will be impacted by fluctuations in prices for natural gas. The price and supply of natural gas is unpredictable and can fluctuate significantly based on international, political and economic circumstances, as well as other events outside our control, such as changes in supply and demand due to weather conditions, actions by OPEC and other oil and natural gas producers, regional production patterns, security threats and environmental concerns. In addition, potential climate change regulations or carbon or emissions taxes could result in higher production costs for energy, which may be passed on to us in whole or in part. In order to manage the risk of volatile natural gas prices, we may hedge natural gas prices through the use of derivative financial instruments, such as forwards, swaps and futures. However, these measures carry risk (including nonperformance by counterparties) and do not in any event entirely eliminate the risk of decreased margins as a result of propane or natural gas price increases. We further attempt to mitigate these risks by including in our sales contracts fuel surcharges based on natural gas prices exceeding certain benchmarks. A significant increase in the price of energy that is not recovered through an increase in the price of our products or covered through our hedging arrangements or an extended interruption in the supply of natural gas or electricity to our production facilities could have a material adverse effect on our business, results of operations and financial condition.

Increases in the price of diesel fuel may adversely affect our business, results of operations and financial condition.

Diesel fuel costs generally fluctuate with increasing and decreasing world crude oil prices and, accordingly, are subject to political, economic and market factors that are outside of our control. Our operations are dependent on earthmoving equipment, locomotives and tractor trailers, and diesel fuel costs are a significant component of the operating expense of these vehicles. Accordingly, increased diesel fuel costs could have an adverse effect on our business, results of operations and financial condition.

A facility closure entails substantial costs, and if we close our facility sooner than anticipated, our results of operations may be adversely affected.

We base our assumptions regarding the life of our Oakdale facility on detailed studies that we perform from time to time, but our studies and assumptions may not prove to be accurate. If we close our Oakdale facility sooner than expected, sales will decline unless we are able to acquire and develop additional facilities, which may not be possible. The closure of our Oakdale facility would involve significant fixed closure costs, including accelerated employment legacy costs, severance-related obligations, reclamation and other environmental costs and the costs of terminating long-term obligations, including energy contracts and equipment leases. We accrue for the costs of reclaiming open pits, stockpiles, non-saleable sand, ponds, roads and other mining support areas over the estimated mining life of our property. If we were to reduce the estimated life of our Oakdale facility, the fixed facility closure costs would be applied to a shorter period of production, which would increase production costs per ton produced and could materially and adversely affect our business, results of operations and financial condition.

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Applicable statutes and regulations require that mining property be reclaimed following a mine closure in accordance with specified standards and an approved reclamation plan. The plan addresses matters such as removal of facilities and equipment, regrading, prevention of erosion and other forms of water pollution, re-vegetation and post-mining land use. We may be required to post a surety bond or other form of financial assurance equal to the cost of reclamation as set forth in the approved reclamation plan. The establishment of the final mine closure reclamation liability is based on permit requirements and requires various estimates and assumptions, principally associated with reclamation costs and production levels. If our accruals for expected reclamation and other costs associated with facility closures for which we will be responsible were later determined to be insufficient, our business, results of operations and financial condition may be adversely affected.

Our operations are dependent on our rights and ability to mine our properties and on our having renewed or received the required permits and approvals from governmental authorities and other third parties.

We hold numerous governmental, environmental, mining and other permits, water rights and approvals authorizing operations at our Oakdale facility. For our extraction and processing in Wisconsin, the permitting process is subject to federal, state and local authority. For example, on the federal level, a Mine Identification Request (MSHA Form 7000-51) must be filed and obtained before mining commences. If wetlands are impacted, a U.S. Army Corps of Engineers Wetland Permit is required. At the state level, a series of permits are required related to air quality, wetlands, water quality (waste water, storm water), grading permits, endangered species, archeological assessments and high capacity wells in addition to others depending upon site specific factors and operational detail. At the local level, zoning, building, storm water, erosion control, wellhead protection, road usage and access are all regulated and require permitting to some degree. A non-metallic mining reclamation permit is required. A decision by a governmental agency or other third party to deny or delay issuing a new or renewed permit or approval, or to revoke or substantially modify an existing permit or approval, could have a material adverse effect on our business, results of operations and financial condition.

Title to, and the area of, mineral properties and water rights may also be disputed. Mineral properties sometimes contain claims or transfer histories that examiners cannot verify. A successful claim that we do not have title to our property or lack appropriate water rights could cause us to lose any rights to explore, develop and extract minerals, without compensation for our prior expenditures relating to such property. Our business may suffer a material adverse effect in the event we have title deficiencies.

A shortage of skilled labor together with rising labor costs in the excavation industry may further increase operating costs, which could adversely affect our business, results of operations and financial condition.

Efficient sand excavation using modern techniques and equipment requires skilled laborers, preferably with several years of experience and proficiency in multiple tasks, including processing of mined minerals. If there is a shortage of experienced labor in Wisconsin, we may find it difficult to hire or train the necessary number of skilled laborers to perform our own operations which could have an adverse impact on our business, results of operations and financial condition.

Our business may suffer if we lose, or are unable to attract and retain, key personnel.

We depend to a large extent on the services of our senior management team and other key personnel. Members of our senior management and other key employees bring significant experience to the market environment in which we operate. Competition for management and key personnel is intense, and the pool of qualified candidates is limited. The loss of any of these individuals or the failure to attract additional personnel, as needed, could have a material adverse effect on our operations and could lead to higher labor costs or the use of less-qualified personnel. In addition, if any of our executives or other key employees were to join a competitor or form a competing company, we could lose customers, suppliers, know-how and key personnel. We do not maintain key-man life insurance with respect to any of our employees. Our success will be dependent on our ability to continue to attract, employ and retain highly skilled personnel.

Failure to maintain effective quality control systems at our mining, processing and production facilities could have a material adverse effect on our business, results of operations and financial condition.

The performance and quality of our products are critical to the success of our business. These factors depend significantly on the effectiveness of our quality control systems, which, in turn, depends on a number of factors, including the design of our quality control systems, our quality-training program and our ability to ensure that our employees adhere to our quality control policies and guidelines. Any significant failure or deterioration of our quality control systems could have a material adverse effect on our business, results of operations and financial condition.

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Seasonal and severe weather conditions could have a material adverse impact on our business, results of operations and financial condition.

Our business could be materially adversely affected by severe weather conditions. Severe weather conditions may affect our customers’ operations, thus reducing their need for our products, impact our operations by resulting in weather-related damage to our facilities and equipment and impact our customers’ ability to take delivery of our products at our plant site. Any weather-related interference with our operations could force us to delay or curtail services and potentially breach our contractual obligations to deliver minimum volumes or result in a loss of productivity and an increase in our operating costs.

In addition, winter weather conditions impact our operations by causing us to halt our excavation and wet plant related production activities during the winter months. During non-winter months, we excavate excess sand to build a stockpile that will feed the dry plants which continue to operate during the winter months. Unexpected winter conditions (such as winter arriving earlier than expected or lasting longer than expected) may result in us not having a sufficient sand stockpile to operate our dry plants during winter months, which could result in us being unable to deliver our contracted sand amounts during such time and lead to a material adverse effect on our business, results of operations and financial condition.

Our cash flow fluctuates on a seasonal basis.

Our cash flow is affected by a variety of factors, including weather conditions and seasonal periods. Seasonal fluctuations in weather impact the production levels at our wet processing plant. While our sales and finished product production levels are contracted evenly throughout the year, our mining and wet sand processing activities are limited to non-winter months. As a consequence, we experience lower cash costs in the first and fourth quarter of each calendar year.

A terrorist attack or armed conflict could harm our business.

Terrorist activities, anti-terrorist efforts and other armed conflicts involving the United States could adversely affect the U.S. and global economies and could prevent us from meeting financial and other obligations. We could experience loss of business, delays or defaults in payments from payors or disruptions of fuel supplies and markets if pipelines, production facilities, processing plants, refineries or transportation facilities are direct targets or indirect casualties of an act of terror or war. Such activities could reduce the overall demand for oil and natural gas, which, in turn, could also reduce the demand for our raw frac sand. Terrorist activities and the threat of potential terrorist activities and any resulting economic downturn could adversely affect our results of operations, impair our ability to raise capital or otherwise adversely impact our ability to realize certain business strategies.

Diminished access to water may adversely affect our operations or the operations of our customers.

The mining and processing activities at our facility requires significant amounts of water. Additionally, the development of oil and natural gas properties through fracture stimulation likewise requires significant water use. We have obtained water rights that we currently use to service the activities at our Oakdale facility, and we plan to obtain all required water rights to service other properties we may develop or acquire in the future. However, the amount of water that we and our customers are entitled to use pursuant to our water rights must be determined by the appropriate regulatory authorities in the jurisdictions in which we and our customers operate. Such regulatory authorities may amend the regulations regarding such water rights, increase the cost of maintaining such water rights or eliminate our current water rights, and we and our customers may be unable to retain all or a portion of such water rights. These new regulations, which could also affect local municipalities and other industrial operations, could have a material adverse effect on our operating costs and effectiveness if implemented. Such changes in laws, regulations or government policy and related interpretations pertaining to water rights may alter the environment in which we and our customers do business, which may negatively affect our financial condition and results of operations.

We may be subject to interruptions or failures in our information technology systems.

We rely on sophisticated information technology systems and infrastructure to support our business, including process control technology. Any of these systems may be susceptible to outages due to fire, floods, power loss, telecommunication failures, usage errors by employees, computer viruses, cyber-attacks or other security breaches, or similar events. If our information technology systems are damaged or cease to function properly, we may have to make a significant investment to fix or replace them, and we may suffer loss of critical data and interruptions or delays in our operations.

We may be the target of attempted cyber attacks, computer viruses, malicious code, phishing attacks, denial of service attacks and other information security threats. To date, cyber attacks have not had a material impact on our financial condition, results or business; however, we could suffer material financial or other losses in the future and we are not able to predict the severity of these attacks. The occurrence of a cyber attack, breach, unauthorized access, misuse, computer virus or other malicious code or other cyber

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security event could jeopardize or result in the unauthorized disclosure, gathering, monitoring, misuse, corruption, loss or destruction of confidential and other information that belongs to us, our customers, our counterparties, or third-party service providers that is processed and stored in, and transmitted through, our computer systems and networks. The occurrence of such an event could also result in damage to our software, computers or systems, or otherwise cause interruptions or malfunctions in our, our customers’, our counterparties’ or third parties’ operations. This could result in significant losses, loss of customers and business opportunities, reputational damage, litigation, regulatory fines, penalties or intervention, reimbursement or other compensatory costs, or otherwise adversely affect our business, financial condition or results of operations.

The reliability and capacity of our information technology systems is critical to our operations. Any material disruption in our information technology systems, or delays or difficulties in implementing or integrating new systems or enhancing current systems, could have an adverse effect on our business, and results of operations.

Risks Related to Environmental, Mining and Other Regulation

We and our customers are subject to extensive environmental and occupational health and safety regulations that impose, and will continue to impose, significant costs and liabilities. In addition, future regulations, or more stringent enforcement of existing regulations, could increase those costs and liabilities, which could adversely affect our results of operations.

We are subject to a variety of federal, state, and local regulatory environmental requirements affecting the mining and mineral processing industry, including among others, those relating to employee health and safety, environmental permitting and licensing, air and water emissions, water pollution, waste management, remediation of soil and groundwater contamination, land use, reclamation and restoration of properties, hazardous materials, and natural resources. Some environmental laws impose substantial penalties for noncompliance, and others, such as the federal CERCLA, may impose strict, retroactive, and joint and several liabilities for the remediation of releases of hazardous substances. Liability under CERCLA, or similar state and local laws, may be imposed as a result of conduct that was lawful at the time it occurred or for the conduct of, or conditions caused by, prior operators or other third parties. Failure to properly handle, transport, store, or dispose of hazardous materials or otherwise conduct our operations in compliance with environmental laws could expose us to liability for governmental penalties, cleanup costs, and civil or criminal liability associated with releases of such materials into the environment, damages to property, natural resources and other damages, as well as potentially impair our ability to conduct our operations. In addition, future environmental laws and regulations could restrict our ability to expand our facilities or extract our mineral deposits or could require us to acquire costly equipment or to incur other significant expenses in connection with our business. Future events, including adoption of new, or changes in any existing environmental requirements (or their interpretation or enforcement) and the costs associated with complying with such requirements, could have a material adverse effect on us.

Any failure by us to comply with applicable environmental laws and regulations may cause governmental authorities to take actions that could adversely impact our operations and financial condition, including:

Any such regulations could require us to modify existing permits or obtain new permits, implement additional pollution control technology, curtail operations, increase significantly our operating costs, or impose additional operating restrictions among our customers that reduce demand for our services.

We may not be able to comply with any new or amended laws and regulations that are adopted, and any new or amended laws and regulations could have a material adverse effect on our operating results by requiring us to modify our operations or equipment or shut down our facility. Additionally, our customers may not be able to comply with any new or amended laws and regulations, which could cause our customers to curtail or cease operations. We cannot at this time reasonably estimate our costs of compliance or the timing of any costs associated with any new or amended laws and regulations, or any material adverse effect that any new or modified standards will have on our customers and, consequently, on our operations.

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Silica-related legislation, health issues and litigation could have a material adverse effect on our business, reputation or results of operations.

We are subject to laws and regulations relating to human exposure to crystalline silica. Several federal and state regulatory authorities, including MSHA, may continue to propose changes in their regulations regarding workplace exposure to crystalline silica, such as permissible exposure limits and required controls and personal protective equipment. We may not be able to comply with any new or amended laws and regulations that are adopted, and any new or amended laws and regulations could have a material adverse effect on our operating results by requiring us to modify or cease our operations.

In addition, the inhalation of respirable crystalline silica is associated with the lung disease silicosis. There is evidence of an association between crystalline silica exposure or silicosis and lung cancer and a possible association with other diseases, including immune system disorders such as scleroderma. These health risks have been, and may continue to be, a significant issue confronting the proppant industry. Concerns over silicosis and other potential adverse health effects, as well as concerns regarding potential liability from the use of raw frac sand, may have the effect of discouraging our customers’ use of our raw frac sand. The actual or perceived health risks of mining, processing and handling proppants could materially and adversely affect proppant producers, including us, through reduced use of frac sand, the threat of product liability or employee lawsuits, increased scrutiny by federal, state and local regulatory authorities of us and our customers or reduced financing sources available to the frac sand industry.

We are subject to the Federal Mine Safety and Health Act of 1977, which imposes stringent health and safety standards on numerous aspects of our operations.

Our operations are subject to the Federal Mine Safety and Health Act of 1977, as amended by the Mine Improvement and New Emergency Response Act of 2006, which imposes stringent health and safety standards on numerous aspects of mineral extraction and processing operations, including the training of personnel, operating procedures, operating equipment, and other matters. Our failure to comply with such standards, or changes in such standards or the interpretation or enforcement thereof, could have a material adverse effect on our business and financial condition or otherwise impose significant restrictions on our ability to conduct mineral extraction and processing operations.

We and our customers are subject to other extensive regulations, including licensing, plant and wildlife protection and reclamation regulation, that impose, and will continue to impose, significant costs and liabilities. In addition, future regulations, or more stringent enforcement of existing regulations, could increase those costs and liabilities, which could adversely affect our results of operations.

In addition to the regulatory matters described above, we and our customers are subject to extensive governmental regulation on matters such as permitting and licensing requirements, plant and wildlife protection, wetlands protection, reclamation and restoration activities at mining properties after mining is completed, the discharge of materials into the environment, and the effects that mining and hydraulic fracturing have on groundwater quality and availability. Our future success depends, among other things, on the quantity and quality of our raw frac sand deposits, our ability to extract these deposits profitably, and our customers being able to operate their businesses as they currently do.

In order to obtain permits and renewals of permits in the future, we may be required to prepare and present data to governmental authorities pertaining to the potential adverse impact that any proposed excavation or production activities, individually or in the aggregate, may have on the environment. Certain approval procedures may require preparation of archaeological surveys, endangered species studies, and other studies to assess the environmental impact of new sites or the expansion of existing sites. Compliance with these regulatory requirements is expensive and significantly lengthens the time needed to develop a site. Finally, obtaining or renewing required permits is sometimes delayed or prevented due to community opposition and other factors beyond our control. The denial of a permit essential to our operations or the imposition of conditions with which it is not practicable or feasible to comply could impair or prevent our ability to develop or expand a site. Significant opposition to a permit by neighboring property owners, members of the public, or other third parties, or delay in the environmental review and permitting process also could delay or impair our ability to develop or expand a site. New legal requirements, including those related to the protection of the environment, could be adopted that could materially adversely affect our mining operations (including our ability to extract or the pace of extraction of mineral deposits), our cost structure, or our customers’ ability to use our raw frac sand. Such current or future regulations could have a material adverse effect on our business and we may not be able to obtain or renew permits in the future.

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Our inability to acquire, maintain or renew financial assurances related to the reclamation and restoration of mining property could have a material adverse effect on our business, financial condition and results of operations.

We are generally obligated to restore property in accordance with regulatory standards and our approved reclamation plan after it has been mined. We are required under federal, state, and local laws to maintain financial assurances, such as surety bonds, to secure such obligations. The inability to acquire, maintain or renew such assurances, as required by federal, state, and local laws, could subject us to fines and penalties as well as the revocation of our operating permits. Such inability could result from a variety of factors, including:

Our inability to acquire, maintain, or renew necessary financial assurances related to the reclamation and restoration of mining property could have a material adverse effect on our business, financial condition, and results of operations.

Climate change legislation and regulatory initiatives could result in increased compliance costs for us and our customers.

In recent years, the U.S. Congress has considered legislation to reduce emissions of GHGs, including methane, a primary component of natural gas, and carbon dioxide, a byproduct of the burning of natural gas. It presently appears unlikely that comprehensive climate legislation will be passed by either house of Congress in the near future, although energy legislation and other regulatory initiatives are expected to be proposed that may be relevant to GHG emissions issues. In addition, a number of states are addressing GHG emissions, primarily through the development of emission inventories or regional GHG cap and trade programs. Depending on the particular program, we could be required to control GHG emissions or to purchase and surrender allowances for GHG emissions resulting from our operations. Independent of Congress, the EPA has adopted regulations controlling GHG emissions under its existing authority under the federal CAA. For example, following its findings that emissions of GHGs present an endangerment to human health and the environment because such emissions contributed to warming of the earth’s atmosphere and other climatic changes, the EPA has adopted regulations under existing provisions of the CAA that, among other things establish construction and operating permit reviews for GHG emissions from certain large stationary sources that are already potential major sources for conventional pollutants. In addition, the EPA has adopted rules requiring the monitoring and reporting of GHG emissions from specified production, processing, transmission and storage facilities in the United States on an annual basis. In addition, in December 2015, over 190 countries, including the United States, reached an agreement to reduce global greenhouse gas emissions, also known as the Paris Agreement.  The Paris Agreement entered into force in November 2016 after more than 170 nations, including the United States, ratified or otherwise indicated their intent to be bound by the agreement.  However, in June 2017, President Trump announced that the United States intends to withdraw from the Paris Agreement and to seek negotiations either to reenter the Paris Agreement on different terms or enter into a separate agreement.  In August 2017, the U.S. Department of State officially informed the United Nations of the United States’ intent 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.  To the extent that the United States and other countries implement this agreement or impose other climate change regulations on the oil and natural gas industry, it could have an adverse effect on our business because substantial limitations on GHG emissions could adversely affect demand for the oil and natural gas that is produced by our customers. Finally, many scientists have concluded 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 and other climatic events; if any such effects were to occur, they could have an adverse effect on our operations and our customers’ exploration and production operations.

Risks Related to Ownership of Our Common Stock

Our stock price could be volatile, and you may not be able to resell shares of your common stock at or above the price you paid.

The stock markets in general have experienced extreme volatility that has often been unrelated to the operating performance of particular companies. These broad market fluctuations may adversely affect the trading price of our common stock. Volatility in the market price of our common stock may prevent you from being able to sell your common stock at or above the price at which you purchased the stock. As a result, you may suffer a loss on your investment. Securities class action litigation has often been instituted against companies following periods of volatility in the overall market and in the market price of a company's securities. Such litigation, if instituted against us, could result in very substantial costs, divert our management's attention and resources and harm our business, operating results and financial condition.

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In addition to the risks described in this section, the market price of our common stock may fluctuate significantly in response to a number of factors, most of which we cannot control, including:

We are subject to certain requirements of Section 404 of the Sarbanes-Oxley Act. If we are unable to timely comply with Section 404 or if the costs related to compliance are significant, our profitability, stock price, results of operations and financial condition could be materially adversely affected.

We are required to comply with certain provisions of Section 404 of the Sarbanes-Oxley Act beginning December 31, 2017. Section 404 requires that we document and test our internal control over financial reporting and issue management’s assessment of our internal control over financial reporting. This section also requires that our independent registered public accounting firm opine on those internal controls upon becoming a large accelerated filer, as defined in the SEC rules, or otherwise ceasing to qualify as an emerging growth company under the JOBS Act. We are evaluating our existing controls against the standards adopted by the Committee of Sponsoring Organizations of the Treadway Commission. During the course of our ongoing evaluation and integration of the internal control over financial reporting, we may identify areas requiring improvement, and we may have to design enhanced processes and controls to address issues identified through this review.

We believe that the out-of-pocket costs, diversion of management’s attention from running the day-to-day operations and operational changes caused by the need to comply with the requirements of Section 404 of the Sarbanes-Oxley Act could be significant. If the time and costs associated with such compliance exceed our current expectations, our results of operations could be adversely affected.

If we fail to comply with the requirements of Section 404 or if we or our independent registered public accounting firm identify and report such material weaknesses, the accuracy and timeliness of the filing of our annual and quarterly reports may be materially adversely affected and could cause investors to lose confidence in our reported financial information, which could have a negative effect on the stock price of our common stock. In addition, a material weakness in the effectiveness of our internal control over financial reporting could result in an increased chance of fraud and the loss of customers, reduce our ability to obtain financing and require additional expenditures to comply with these requirements, each of which could have a material adverse effect on our business, results of operations and financial condition.

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The concentration of our capital stock ownership among our largest stockholders and their affiliates will limit your ability to influence corporate matters.

As of December 31, 2017, Clearlake beneficially owns approximately 26.4% of our outstanding common stock and our Chief Executive Officer beneficially owns approximately 15.2% of our outstanding common stock. Consequently, Clearlake and our Chief Executive Officer (each of whom we sometimes refer to as a “Principal Stockholder”) will continue to have significant influence over all matters that require approval by our stockholders, including the election of directors and approval of significant corporate transactions. Additionally, we are party to a stockholders’ agreement pursuant to which, so long as either Principal Stockholder maintains certain beneficial ownership levels of our common stock, each Principal Stockholder will have certain rights, including board of directors and committee designation rights and consent rights, including the right to consent to change in control transactions. For additional information, please read “Certain Relationships and Related Party Transactions—Stockholders Agreement” in the prospectus included in our Registration Statement on Form S-1 (Registration No. 333-215554), initially filed with the SEC on January 13, 2017.  This concentration of ownership and the rights of our Principal Stockholders under the stockholders agreement, will limit your ability to influence corporate matters, and as a result, actions may be taken that you may not view as beneficial.

Furthermore, conflicts of interest could arise in the future between us, on the one hand, and Clearlake and its affiliates, including its portfolio companies, on the other hand, concerning among other things, potential competitive business activities or business opportunities. Clearlake is a private equity firm in the business of making investments in entities in a variety of industries. As a result, Clearlake’s existing and future portfolio companies which it controls may compete with us for investment or business opportunities. These conflicts of interest may not be resolved in our favor.

The price of our common stock may fluctuate significantly, and you could lose all or part of your investment.

As of December 31, 2017, there were 21,869,074 publicly traded shares of common stock held by our public common stockholders. Although our common stock is listed on the NASDAQ, we do not know whether an active trading market will continue to develop or how liquid that market might be. You may not be able to resell your common stock at or above the public offering price. Additionally, the lack of liquidity may result in wide bid-ask spreads, contribute to significant fluctuations in the market price of the common stock and limit the number of investors who are able to buy the common stock.

Our amended and restated certificate of incorporation contains a provision renouncing our interest and expectancy in certain corporate opportunities.

Our amended and restated certificate of incorporation provides for the allocation of certain corporate opportunities between us and Clearlake. Under these provisions, neither Clearlake, its affiliates and investment funds, nor any of their respective principals, officers, members, managers and/or employees, including any of the foregoing who serve as our officers or directors, will have any duty to refrain from engaging, directly or indirectly, in the same business activities or similar business activities or lines of business in which we operate. For instance, a director of our company who also serves or is a principal, officer, member, manager and/or employee of Clearlake or any of its affiliates or investment funds may pursue certain acquisitions or other opportunities that may be complementary to our business and, as a result, such acquisition or other opportunities may not be available to us. These potential conflicts of interest could have a material adverse effect on our business, financial condition and results of operations if attractive corporate opportunities are allocated by Clearlake to itself or its affiliates or investment funds instead of to us. The terms of our amended and restated certificate of incorporation are more fully described in “Description of Capital Stock” in the prospectus included in our Registration Statement on Form S-1 (Registration No. 333-215554), initially filed with the SEC on January 13, 2017.

If securities or industry analysts do not publish research or reports or publish unfavorable research about our business, the price and trading volume of our common stock could decline.

The trading market for our common stock depends in part on the research and reports that securities or industry analysts publish about us or our business. If one or more of the analysts who covers us downgrades our securities, the price of our securities would likely decline. If one or more of these analysts ceases to cover us or fails to publish regular reports on us, interest in the purchase of our securities could decrease, which could cause the price of our common stock and other securities and their trading volume to decline.

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Our amended and restated certificate of incorporation and amended and restated bylaws, as well as Delaware law, contain provisions that could discourage acquisition bids or merger proposals, which may adversely affect the market price of our common stock.

Our amended and restated certificate of incorporation authorizes our board of directors to issue preferred stock without stockholder approval. If our board of directors elects to issue preferred stock, it could be more difficult for a third party to acquire us. In addition, some provisions of our amended and restated certificate of incorporation and amended and restated bylaws could make it more difficult for a third party to acquire control of us, even if the change of control would be beneficial to our stockholders, including:

We do not currently, and do not intend to, pay dividends on our common stock, and our debt agreements place certain restrictions on our ability to do so. Consequently, your only opportunity to achieve a return on your investment is if the price of our common stock appreciates.

We do not currently, and do not plan to, declare dividends on shares of our common stock in the foreseeable future. Additionally, our existing revolving credit facility places certain restrictions on our ability to pay cash dividends. Consequently, unless we revise our dividend policy, your only opportunity to achieve a return on your investment in us will be if you sell your common stock at a price greater than you paid for it. There is no guarantee that the price of our common stock that will prevail in the market will ever exceed the price that you previously paid.

Future sales of our common stock in the public market could reduce our stock price, and the sale or issuance of equity or convertible securities may dilute your ownership in us.

We may sell additional shares of common stock in subsequent public offerings. We may also issue additional shares of common stock or convertible securities. As of December 31, 2017, we have outstanding 40,927,384 shares of common stock. Clearlake beneficially owns 10,821,091 shares of our common stock, or approximately 26.4% of our total outstanding shares and our Chief Executive Officer beneficially owns 6,207,050 shares of our common stock, or approximately 15.2% of our total outstanding shares. All of the shares beneficially owned by Clearlake and our Chief Executive Officer are restricted from immediate resale under the federal securities laws and are subject to the lock-up agreements with the underwriters, but may be sold into the market in the future.

In connection with our initial public offering, we filed a registration statement with the SEC on Form S-8 providing for the registration of shares of our common stock issued or reserved for issuance under our equity incentive plans. Subject to the satisfaction of vesting conditions, the expiration of lock-up agreements and the requirements of Rule 144, shares registered under the registration statement on Form S-8 will be available for resale immediately in the public market without restriction.

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We have provided certain registration rights for the sale of common stock by certain existing stockholders, including the selling shareholders, in the future. The sale of these shares could have an adverse impact on the price of our common stock or on any trading market that may develop.

We cannot predict the size of future issuances of our common stock or securities convertible into common stock or the effect, if any, that future issuances and sales of shares of our common stock will have on the market price of our common stock. Sales of substantial amounts of our 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 common stock.

We are an “emerging growth company” and we cannot be certain if the reduced disclosure requirements applicable to emerging growth companies will make our common stock less attractive to investors.

We are an “emerging growth company”, as defined in the JOBS Act, and we intend to take advantage of certain exemptions from various reporting requirements that are applicable to other public companies, including, but not limited to, not being required to comply with the auditor attestation requirements of Section 404 of the Sarbanes-Oxley Act, 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 these reporting exemptions until we are no longer an emerging growth company. We cannot predict if investors will find our common stock less attractive because we will rely on these exemptions. If some investors find our common stock less attractive as a result, there may be a less active trading market for our common stock and our stock price may be more volatile.

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.

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 have irrevocably elected not to avail ourselves of this exemption from new or revised accounting standards and, therefore, we will be subject to the same new or revised accounting standards as other public companies that are not emerging growth companies.

To the extent that we rely on any of the exemptions available to emerging growth companies, you will receive less information about our executive compensation and internal control over financial reporting than issuers that are not emerging growth companies.

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

Our amended and restated certificate of incorporation will designate 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 will provide 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 arising pursuant to any provision of the Delaware General Corporation Law (the “DGCL”), our amended and restated certificate of incorporation or our bylaws, or (iv) any action asserting a claim against us 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. 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

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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.

Item 1B. – Unresolved Staff Comments

None

Item 2. – Properties

Our Oakdale facility is purpose-built to exploit the reserve profile in place and produce high-quality raw frac sand. Unlike some of our competitors, our mine, processing plants and primary rail loading facilities are in one location, which limits the need for us to truck sand on public roads between the mine and the production facility or between wet and dry processing facilities. Our on-site transportation assets include approximately nine miles of rail track in a triple-loop configuration and four railcar loading facilities that are connected to a Class I rail line owned by Canadian Pacific, which enables us to simultaneously accommodate multiple unit trains and significantly increases our efficiency in meeting our customers’ raw frac sand transportation needs. We ship a substantial portion of our sand volumes (approximately 76% in 2017) in unit train shipments through railcars that either we lease or our customers own or lease and deliver to our facility. We believe that we are one of the few raw frac sand producers with a facility custom-designed for the specific purpose of delivering raw frac sand to all of the major U.S. oil and natural gas producing basins by an on-site rail facility that can simultaneously accommodate multiple unit trains. Our ability to handle multiple railcar sets allows for the efficient transition of locomotives from empty inbound trains to fully loaded outbound trains at our facility.

We believe our customized on-site logistical configuration yields lower overall operating and transportation costs compared to manifest train or single-unit train facilities as a result of our higher railcar utilization, more efficient use of locomotive power and more predictable movement of product between mine and destination. Unit train operations such as ours can double or triple the average number of loads that a railcar carries per year, thus reducing the number of railcars needed to support our operations and limiting our exposure to unutilized railcars and the corresponding storage and lease expense. We believe that our Oakdale facility’s connection to the Canadian Pacific rail network, combined with our unit train logistics capabilities, provides us with enhanced flexibility to serve customers located in shale plays throughout North America. In addition, we have invested in a transloading facility on the Union Pacific rail network in Byron Township, Wisconsin, approximately 3.5 miles from our Oakdale facility. This facility is operational and provides us with the ability to ship unit trains directly on the Union Pacific network to locations in the major operating basins in the Western and Southwestern United States, which should facilitate more competitive pricing among our rail carriers. With the addition of this transload facility, we believe we are the only raw frac sand mine in Wisconsin with dual served railroad shipment capabilities on the Canadian Pacific and Union Pacific, which should provide us more competitive logistics options to the market relative to other Wisconsin-based sand mining and production facilities.

In addition to the Oakdale facility, our Hixton site consists of approximately 959 acres in Jackson County, Wisconsin. The Hixton site is fully permitted to initiate operations and is available for future development. As of December 31, 2017, our Hixton site had approximately 100 million tons of proven recoverable sand reserves. This location is located on a Class I rail line, the Canadian National.

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The following tables provide key characteristics of our Oakdale facility and Hixton site:

Our Oakdale Facility (as of December 31, 2017)

Our Hixton Site (as of December 31, 2017)

We have entered into two long-term surface mining leases for properties located in the Permian Basin in Texas that are available for future development.  The first site consists of 1772 acres in Winkler County, Texas.  This location is adjacent to the Texas & New Mexico Railway (TXN) short line with direct access to State Highway 18.  The second site consists of 2,447 acres in Crane County, Texas.  This location has direct access to Interstate Highway 20 and has been awarded a Certificate of Inclusion into the TCP for the dunes sagebrush lizard.  The TCP is designed to protect dunes sagebrush lizard habitat while facilitating continued and uninterrupted economic activity in the Permian Basin.  The Permian Basin sites have been acquired for a combined cost of less than $5,000,000 and have low associated royalty payments. We estimate that the sites collectively have several hundred million tons of frac sand reserves.

Our Reserves

We believe that our strategically located Oakdale and Hixton sites provide us with a large and high-quality mineral reserves base. Mineral resources and reserves are typically classified by confidence (reliability) levels based on the level of exploration, consistency and assurance of geologic knowledge of the deposit. This classification system considers different levels of geoscientific knowledge and varying degrees of technical and economic evaluation. Mineral reserves are derived from in situ resources through application of modifying factors, such as mining, analytical, economic, marketing, legal, environmental, social and governmental factors, relative to mining methods, processing techniques, economics and markets. In estimating our reserves, John T. Boyd does not classify a resource as a reserve unless that resource can be demonstrated to have reasonable certainty to be recovered economically in accordance with the modifying factors listed above. “Reserves” are defined by SEC Industry Guide 7 as that part of a mineral deposit that could be economically and legally extracted or produced at the time of the reserve determination. Industry Guide 7 defines “proven (measured) reserves” as reserves for which (a) quantity is computed from dimensions revealed in outcrops, trenches, workings or drill holes; grade and/or quality are computed from the results of detailed sampling and (b) the sites for inspection, sampling and measurement are spaced so closely and the geologic character is so well defined that size, shape, depth and mineral content of reserves are well-established.

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In estimating our reserves, as listed in the table above, John T. Boyd categorizes our reserves as proven recoverable in accordance with these SEC definitions. The quantity and nature of the sand reserves at our Oakdale site are estimated by third-party geologists and mining engineers, and we internally track the depletion rate on an interim basis. Before acquiring new reserves, we perform surveying, drill core analysis and other tests to confirm the quantity and quality of the acquired reserves.

Our Oakdale reserves are located on 1,196 contiguous acres in Monroe County, Wisconsin. We own our Monroe County acreage in fee and acquired surface and mineral rights on all of such acreage from multiple landowners in separate transactions. Our mineral rights are subject to an aggregate non-participating royalty interest of $0.50 per ton sold of coarser than 70 mesh, which we believe is significantly lower than many of our competitors.

In addition to the Oakdale facility, we own the Hixton site that is on approximately 959 acres in Jackson County, Wisconsin. The Hixton site is fully permitted and available for future development. We own our Jackson County acreage in fee and acquired surface and mineral rights on all of such acreage from multiple landowners in separate transactions. Our mineral rights are subject to an aggregate non-participating royalty interest of $0.50 per ton sold of coarser than 70 mesh, which we believe is significantly lower than many of our competitors.

To opine as to the economic viability of our reserves, John T. Boyd reviewed our financial cost and revenue per ton data at the time of the reserve determination. Based on their review of our cost structure and their extensive experience with similar operations, John T. Boyd concluded that it is reasonable to assume that we will operate under a similar cost structure over the remaining life of our reserves. John T. Boyd further assumed that if our revenue per ton remained relatively constant over the life of the reserves, our current operating margins are sufficient to expect continued profitability throughout the life of our reserves.

The cutoff grade used by John T. Boyd in estimating our reserves considers sand that falls between 20 and 140 mesh sizes as proven recoverable reserves, meaning that sands within this range are included in John T. Boyd’s estimate of our proven recoverable. In addition, John T. Boyd’s estimate of our reserves adjusts for mining losses of 10% and processing losses through the wet plant and dry plants, for a total yield of the in-place sand resource. Our processing losses are primarily due to minus 140 mesh sand being removed at the wet processing plant, plus 20 mesh sand being removed in the dry plants (including moisture) through normal attrition and all other material discarded as waste (including clay and other contaminants).

During wet plant processing operations, the wet plant process water leaving the wet plant is pumped into a settling basin for the ultra-fine (minus 140 mesh) sand to settle. The settling basin allows the wet plant process water to flow back to the fresh water pump pond via a canal system to its original starting point. The fresh water pump pond, wet plant, settling basin and canal system complete an enclosed circuit for continuous recycled wet plant process water.

Wet plant process tailings are temporarily piled and/or stored. Tailings are systematically used throughout the mining operation for various purposes such as reclamation, roads and soil stabilization. Dry plant process material discharged during the drying process is temporarily piled and/or stored for various purposes such as reclamation and soil stabilization, and it is commonly recycled through the wet plant process.

Our Oakdale reserves are a mineral resource deposited over millions of years. Approximately 500 million years ago, quartz rich Cambrian sands were deposited in the upper Midwest region of the United States. During the Quaternary era, glaciation and erosion caused by the melting of glaciers removed millions of years of bedrock, to expose the Cambrian sandstone deposit, near the surface. Our deposits are located in an ancient marine setting, which is the reason our deposit is well sorted and rounded. The high quartz content of the Cambrian sands and the monocrystalline structure of our deposits are responsible for the extremely high crush strength relative to other types of sand. The deposit found in our open-pit Oakdale mine and our Hixton site is a Cambrian quartz sandstone deposit that produces high-quality Northern White raw frac sand with a silica content of 99%.

Although crush strength is one of a number of characteristics that define the quality of raw frac sand, it is a key characteristic for our customers and other purchasers of raw frac sand in determining whether the product will be suitable for its desired application. For example, raw frac sand with exceptionally high crush strength is suitable for use in high pressure downhole conditions that would otherwise require the use of more expensive resin-coated or ceramic proppants.

The sand deposit at our formation does not require crushing or extensive processing to eliminate clays or other contaminants, enabling us to cost-effectively produce high-quality raw frac sand meeting API specifications. In addition, the sand deposit is present to a depth of approximately 200 feet, with a generally shallow overburden of less than 10 feet, on average, over the entire property. The shallow depth of the sand deposits allows us to conduct surface mining rather than underground mining, which lowers our production costs and decreases safety risks as compared to underground mining. All of our surface mining is currently conducted utilizing excavators and trucks to deliver sand to the wet plant. We have considered utilizing other mining methods, such as a dredge operation, and may continue evaluating other mining methods from time to time in the future.

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Our Oakdale Facility

We commenced operations at our Oakdale facility in July 2012. Prior to our commencement of operations, we performed surveying, drill core analysis and other tests to confirm the quantity and quality of the reserves. The process was performed with the assistance of John T. Boyd. Before acquiring new acreage in the future, including material additional acreage adjacent to our Oakdale site, we will perform similar procedures.

Our Oakdale wet plant facilities are comprised of steel structures and rely primarily on industrial grade aggregate processing equipment. Our second wet plant facility was brought online in October 2017 and will be fully operational as of the second quarter of 2018. Each of our Oakdale dry plants contain one 200 ton per hour propane- or natural gas-fired fluid bed dryer. Our first and third dry plants have six high-capacity mineral separators, and our second dry plant has four high-capacity mineral separators. Each dryer is capable of producing approximately 1.1 million tons per year of dry Northern White raw frac sand in varying gradations, including 20/40, 30/50, 40/70 and 100 mesh. Our first three dry plants are enclosed in separate buildings. Our first wet plant is in process of being retrofitted to increase its wet sand production capacity and to extend the wet processing season prior to winter shutdown.

Our fourth and fifth dry plant facilities will be fully operational as of the second quarter 2018.  These facilities will have twelve high-capacity mineral separators and two 200 ton per hour propane-or natural gas-fired fluid bed dryers, bringing our total nameplate drying capacity in Oakdale, WI to approximately 5.5 million tons. As part of our expansion, our second wet plant and fourth and fifth dry plants and supporting infrastructure will be located inside a single insulated metal building designed to increase efficiencies and minimize weather-related effects during the winter months. As a result of this enclosure, we do not anticipate shutting down our second wet plant for the winter season.

For the year ended December 31, 2017, we sold approximately 2.4 million tons of raw frac sand. A substantial portion of our sales volumes have historically, and are currently, sold FCA our Oakdale facility. During 2017, we experienced an increase in FCA basin sales. Generally, logistics costs can comprise 60-80% of the delivered cost of Northern White raw frac sand, depending on the basin into which the product is delivered.

The surface excavation operations at our Oakdale site are conducted by our employees with leased or purchased heavy equipment. The mining technique at our Oakdale site is open-pit excavation of our silica deposits. The excavation process involves clearing and grubbing vegetation and trees overlying the proposed mining area. The initial shallow overburden is removed and utilized to construct perimeter berms around the pit and property boundary. No underground mines are operated at our Oakdale site. In certain situations where the sand-bearing geological formation is tightly cemented, we utilize blasting to make the sand easier to excavate.

A track excavator and articulated trucks are utilized for excavating the sand at several different elevation levels of the active pit. The pit is dry mined, and the water elevation is maintained below working level through a dewatering and pumping process. The mined material is loaded and hauled from different areas of the pit and different elevations within the pit to the primary loading facility at our mine’s on-site wet processing facility.

Once processed and dried, sand from our Oakdale facility is stored in one of ten on-site silos with a combined storage capacity of 27,000 tons. In addition to the 27,000 tons of silo capacity, we own approximately nine miles of on-site rail track (in a triple-loop configuration) that is connected to the Canadian Pacific rail network and that is used to stage and store empty or recently loaded customer railcars. Our strategic location adjacent to a Canadian Pacific mainline provides our customers with the ability to transport Northern White raw frac sand from our Oakdale facility to all major unconventional oil and natural gas basins currently producing in the United States. For additional information regarding our transportation logistics and infrastructure, please read “—Transportation Logistics and Infrastructure.”

Our Oakdale facility undergoes regular maintenance to minimize unscheduled downtime and to ensure that the quality of our raw frac sand meets applicable API and ISO standards and our customers’ specifications. In addition, we make capital investments in our facility as required to support customer demand and our internal performance goals. Except for planned and unplanned downtime, our dry plants operate year-round.

As of December 31, 2017, we have utilized approximately 221 acres for facilities and mining operations, or only 19% of Oakdale location.

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Transportation Logistics and Infrastructure

Historically, all of our product has been shipped by rail from our Oakdale facility. Our rail infrastructure now consists of an approximately nine-mile on-site rail spur, in a triple-loop configuration, that connects our Oakdale facility to a Canadian Pacific mainline. The length of this rail spur and the capacity of the associated product storage silos allow us to accommodate a large number of railcars. This configuration also enables us to accommodate multiple unit trains simultaneously, which significantly increases our efficiency in meeting our customers’ raw frac sand transportation needs. Unit trains, typically 100 railcars in length or longer, are dedicated trains chartered for a single delivery destination. Generally, unit trains receive priority scheduling and do not switch cars at various intermediate junctions, which results in a more cost-effective and efficient method of shipping than the standard method of rail shipment. While many of our competitors may be able to handle a single unit train, we believe that our Oakdale facility is one of the few raw frac sand facilities in the industry that is able to simultaneously accommodate multiple unit trains in its rail yard.

The ability to handle multiple railcar sets is particularly important in order to allow for the efficient transition of the locomotive from empty inbound trains to fully-loaded outbound trains at the originating mine. For example, in a “hook-and-haul” operation, inbound locomotive power arriving at the mine unhooks from an empty train and hooks up to a fully loaded unit car train waiting at the rail yard with a turnaround time of as little as two hours. We believe that this type of operation typically yields lower operating and transportation costs compared to manifest train traffic movements as a result of higher railcar utilization, more efficient use of locomotive power and more predictable movement of product between mine and destination. We believe that this is a key differentiator as currently railcars are in high demand in the industry and hook-and-haul operations can increase the average number of turns per year of a railcar from seven to nine turns per year for manifest train shipments to over 20 turns per year for unit train shipments, while also reducing demand variability for locomotive services. We believe that we are one of the few raw frac sand producers with a facility custom-designed for the specific purpose of delivering raw frac sand to all of the major U.S. oil and natural gas producing basins by an on-site rail facility that can simultaneously accommodate multiple unit trains, a capability that requires sufficient acreage, loading facilities and rail spurs.

In addition, we have expanded our transload facility on a rail line owned by the Union Pacific in Byron Township, Wisconsin, approximately 3.5 miles from the Oakdale facility to be fully unit train capable. This transload facility, which includes approximately 5 miles of rail spur in a double-loop configuration, allows us to ship sand directly to our customers on more than one rail carrier. This facility has been operational since June 2016 and we shipped our first unit train from this facility in December 2017. We believe this facility should provide increased delivery options for our customers, greater competition among our rail carriers and potentially lower freight costs. With the addition of this transload facility, we believe we are the only mine in Wisconsin with dual served railroad shipment capabilities on the Canadian Pacific and Union Pacific railroads, which should provide us more competitive logistics options to the market relative to other Wisconsin-based sand mining and production facilities.

The logistics capabilities of raw frac sand producers are important to customers, who focus on both the reliability and flexibility of product delivery. Because our customers generally find it impractical to store raw frac sand in large quantities near their job sites, they seek to arrange for product to be delivered where and as needed, which requires predictable and efficient loading and shipping of product. The integrated nature of our logistics operations, our approximate nine-mile on-site rail spur and our ability to ship using unit trains enable us to handle railcars for multiple customers simultaneously, which:

In addition, with the transload facility now operational at Byron Township, our Oakdale facility is now dual served and capable of shipping sand directly on the Canadian Pacific and Union Pacific rail lines. Together, these advantages provide our customers with a reliable and efficient delivery method from our facility to each of the major U.S. oil and natural gas producing basins, and allow us to take advantage of the increasing demand for such a delivery method.

Item 3. – Legal Proceedings

From time to time we may be involved in litigation relating to claims arising out of our operations in the normal course of business. We are not currently a party to any legal proceedings that we believe would have a material adverse effect on our financial position, results of operations or cash flows and are not aware of any material legal proceedings contemplated by governmental authorities.

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Item 4. – Mine Safety Disclosures

Our operations are subject to the Federal Mine Safety and Health Act of 1977, as amended by the Mine Improvement and New Emergency Response Act of 2006, which imposes stringent health and safety standards on numerous aspects of mineral extraction and processing operations, including the training of personnel, operating procedures, operating equipment, and other matters. Our failure to comply with such standards, or changes in such standards or the interpretation or enforcement thereof, could have a material adverse effect on our business and financial condition or otherwise impose significant restrictions on our ability to conduct mineral extraction and processing operations. Following passage of The Mine Improvement and New Emergency Response Act of 2006, MSHA significantly increased the numbers of citations and orders charged against mining operations.  The dollar penalties assessed for citations issued has also increased in recent years.  Information concerning mine safety violations or other regulatory matters required by Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K (17 CFR 229.104) is included in Exhibit 95.1 to this Report.

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PART II

Item 5. – Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Shares of our common stock, traded publicly under the symbol, “SND,” have been publicly traded since November 4, 2016, when our common stock was listed and began trading on the NASDAQ Global Select Market (“NASDAQ”).  Prior to that date, there was no public market for our stock.

The following table sets forth, for the reporting period indicated, the high and low market prices per share of our common stock, as reported on the NASDAQ.

Holders of Record

On March 12, 2018, there were 40,946,060 shares of our common stock outstanding, which were held by approximately 29 stockholders of record. Because many of our shares of common stock are held by brokers and other institutions on behalf of stockholders, we are unable to estimate the total number of stockholders represented by these record holders.

Dividends

Our ability to pay dividends is governed by (i) the provisions of Delaware corporate law, (ii) our Certificate of Incorporation and Bylaws, and (iii) our revolving credit facility.  We have not paid or declared any dividends on our common stock.  The future payment of cash dividends on our common stock, if any, is within the discretion of our board of directors and will depend on our earnings, capital requirements, financial condition, and other relevant factors.  To date, we have not paid any dividends on our common stock, and there is no assurance that we will pay any cash dividends on our common stock in the future.

Smart Sand, Inc. Comparative Stock Performance Graph

The graph below compares the cumulative total shareholder return on our common stock, the cumulative total return on the Russell 3000 Index, the Standard and Poor’s Small Cap 600 GICS Oil & Gas Equipment & Services Sub-Industry Index and a composite average of publicly traded proppant peer companies (Fairmount Santrol Holding, Inc., U.S. Silica Holding, Inc., Hi-Crush Partners LP, CARBO Ceramics, Inc. and Emerge Energy Services, LP) since November 4, 2016, the first day our stock traded on the NASDAQ.

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The Graph assumes $100 was invested on November 4, 2016, the first day our stock was traded on the NASDAQ, in our common stock, the Russell 3000, the Standard and Poor’s Small Cap 600 GICS Oil &Gas Equipment & Services Sub-Industry Index and a composite of publicly traded proppant peer companies. The cumulative total return assumes the reinvestment of all dividends. We elected to include the stock performance of a composite of our publicly traded peers as we believe it is an appropriate benchmark for our line of business/industry.

The information contained in this Smart Sand, Inc. Comparative Stock Performance Graph section shall not be deemed to be “soliciting material” or “filed” or incorporated by reference in future filings with the SEC, or subject to the liabilities of Section 18 of the Exchange Act, except to the extent that we specifically incorporate it by reference into a document filed under the Securities Act or the Exchange Act.

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Item 6. – Selected Financial Data

The selected historical consolidated financial data presented below should be read in conjunction with “Risk Factors,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our consolidated financial statements and the related notes and other financial data included elsewhere in this document.

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Item 7. – Management’s Discussion and Analysis of Financial Condition and Results of Operations

Forward-Looking Statements

The following discussion and analysis of our financial condition and results of operations should be read together with Item 6, “Selected Financial Data,” Item 1, “Business,” and the Consolidated Financial Statements in Part II, Item 8 of this Annual Report on Form 10-K and the related notes included elsewhere in this report. This discussion contains forward-looking statements as a result of many factors, including those set forth under Item 1, “Business—Forward-Looking Statements” and Item 1A, “Risk Factors,” and elsewhere in this Annual Report on Form 10-K. These statements are based on current expectations and assumptions that are subject to risks and uncertainties. Actual results could differ materially from those discussed in or implied by forward-looking statements. Factors that could cause or contribute to these differences include those discussed below and elsewhere in this report, particularly in Item 1A, “Risk Factors.” All share amounts are presented in thousands.

Overview

We are a pure-play, low-cost producer of high-quality Northern White raw frac sand, which is a preferred proppant used to enhance hydrocarbon recovery rates in the hydraulic fracturing of oil and natural gas wells. We sell our products primarily to oil and natural gas exploration and production companies and oilfield service companies under a combination of long-term take-or-pay contracts and spot sales in the open market. We believe that the size and favorable geologic characteristics of our sand reserves, the strategic location and logistical advantages of our facilities and the industry experience of our senior management team have positioned us as a highly attractive source of raw frac sand to the oil and natural gas industry.

We own and operate a raw frac sand mine and related processing facility near Oakdale, Wisconsin, at which we have approximately 321 million tons of nameplate proven recoverable sand reserves as of December 31, 2017. We began operations with 1.1 million tons of nameplate processing capacity in July 2012, expanded to 2.2 million tons capacity in August 2014, and increased to 3.3 million tons of nameplate capacity in September 2015. Our integrated Oakdale facility, with on-site rail infrastructure and wet and dry sand processing facilities, has access to two Class I rail lines and enables us to process and cost-effectively deliver up to approximately 3.3 million tons of raw frac sand per year. Based on our assessment of increased demand for our products, we are increasing our nameplate processing capacity to approximately 5.5 million tons of raw frac sand per year. This expansion is expected to be completed during the second quarter of 2018.

Our Assets and Operations

Our sand reserves include a balanced concentration of coarse (20/40, 30/50 and 40/70 gradation) sands and fine (60/140 gradation, which we refer to in this annual report as “100 mesh”) sand. Our reserves contain deposits of approximately 19% of 20/40 and coarser substrate, 41% of 40/70 mesh substrate and approximately 40% of 100 mesh substrate. Our 30/50 gradation is a derivative of the 20/40 and 40/70 blends. We believe that this mix of coarse and fine sand reserves, combined with contractual demand for our products across a range of mesh sizes, provides us with relatively higher mining yields and lower processing costs than frac sand mines with predominantly coarse sand reserves. In addition, our approximate 321 million tons of proven recoverable reserves implies a reserve life of approximately 97 years based on our current annual nameplate processing capacity of 3.3 million tons per year. This long reserve life enables us to better serve demand for different types of raw frac sand as compared to mines with shorter reserve lives.

Our Oakdale facility is purpose-built to exploit the reserve profile in place and produce high-quality raw frac sand. Unlike some of our competitors, our primary processing and rail loading facilities are located in close proximity to the mine site, which limits the need for us to truck sand on public roads between the mine and the production facility or between wet and dry processing facilities. Our on-site transportation assets include approximately nine miles of rail track in a triple-loop configuration and four railcar loading facilities that are connected to a Class I rail line owned by Canadian Pacific. This enables us to simultaneously accommodate multiple unit trains and significantly increases our efficiency in meeting our customers’ raw frac sand transportation needs. With the addition of our unit train capable transload facility approximately 3.5 miles from the Oakdale facility in Byron Township, Wisconsin, we also have the ability to ship sand to our customers on the Union Pacific network. We believe that we are the only sand facility in Wisconsin that has dual served rail capabilities, which should create competition among our rail carriers and allow us to provide more competitive logistics options for our customers. Most of our product is shipped via unit trains, which we believe should yield lower operating and transportation costs compared to manifest train or single-unit train facilities due to our higher railcar utilization, more efficient use of locomotive power and more predictable movement of products between mine and destination. We believe that the combination of efficient production and processing, our well-designed plant, our dual served rail access and our focus on shipping sand in unit trains offer a considerable economic advantage to our customers.

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Overall Trends and Outlook

Industry Trends Impacting Our Business

Unless otherwise indicated, the information set forth under “—Industry Trends Impacting Our Business,” including all statistical data and related forecasts, is derived from The Freedonia Group’s Industry Study #3535, “Proppants Market in North America,” published in July 2017, Spears’ “Hydraulic Fracturing Market 2006 - 2018” published in the fourth quarter of 2017 and the supplement published in the first quarter of 2018, and Baker Hughes’ “North America Rotary Rig Count” published in February 2018. While we are not aware of any misstatements regarding the proppant industry data presented herein, estimates involve risks and uncertainties and are subject to change based on various factors, including those discussed under the heading “Risk Factors”.

Demand Trends

According to Spears, the U.S. proppant market, including raw frac sand, ceramic and resin-coated proppant, was approximately 103 million tons in 2017. Freedonia estimates that the total raw frac sand market in 2017 represented approximately 96.5% of the total proppant market by weight. According to Spears, market demand in 2017 increased by approximately 41% from the prior record set in 2014. Spears estimates that over the next three years proppant demand will grow by 12.5% per year, from 103 million tons per year in 2017 to 165 million tons per year in 2020, representing an increase of approximately 62 million tons in annual proppant demand over that time period.

Demand growth for raw frac sand and other proppants is primarily driven by advancements in oil and natural gas drilling and well completion technology and techniques, such as horizontal drilling and hydraulic fracturing. These advancements have made the extraction of oil and natural gas increasingly cost-effective in formations that historically would have been uneconomic to develop. While current horizontal rig counts have fallen significantly from their peak of approximately 1,370 in 2014 to approximately 800 at the end of 2017, rig count grew 254% from the recent low of approximately 315 rigs in May of 2016 to approximately 800 at the end of 2017. According to the Baker Hughes Rig Count, the percentage of active drilling rigs used to drill horizontal wells, which require greater volumes of proppant than vertical wells, has increased from 68.4% in 2014 to 83.9% in 2017. Moreover, the increase of pad drilling has led to a more efficient use of rigs, allowing more wells to be drilled per rig. As a result of these factors, well count, and hence proppant demand, has grown despite the fall in rig counts. Spears estimates that proppant demand will reach 142 million tons in 2018, which is nearly twice the 2014 levels of approximately 73 million tons, despite their projection assuming that approximately 4,600 fewer wells will be drilled in 2018 as compared to 2014. Spears also estimates that average proppant usage per well will be approximately 7,100 tons per well in 2018 and rise to approximately 7,700 tons per well by 2020.

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Demand for proppant has sharply increased since 2016 in connection with the ongoing recovery in commodity prices and the corresponding increase in oil and natural gas drilling and production activity. We believe that the demand for proppant will continue to increase over the medium and long term as commodities stabilize from their lows in 2016, which will lead producers to continue to draw down their inventory of drilled but uncompleted wells and undertake new drilling activities. Further, we believe that demand for proppant will be amplified by the following factors:

Recent growth in demand for raw frac sand has outpaced growth in demand for other proppants, and industry analysts predict that this trend will continue. As well completion costs have increased as a proportion of total well costs, operators have increasingly looked for ways to improve per well economics by lowering costs without sacrificing production performance. To this end, the oil and natural gas industry is shifting away from the use of higher-cost proppants towards more cost-effective proppants, such as raw frac sand. Evolution of completion techniques and the substantial increase in activity in U.S. oil and liquids-rich resource plays has further accelerated the demand growth for raw frac sand.

Historically, oil and liquids-rich wells use a higher proportion of coarser proppant while dry gas wells typically use finer grades of sand. In the past, with the majority of U.S. exploration and production spending focused on oil and liquids-rich plays, demand for coarser grades of sand exceeded demand for finer grades; however, due to innovations in completion techniques, demand for finer grade sands has shown a considerable resurgence.

Supply Trends

In 2017, customer demand for high-quality raw frac sand outpaced supply. Several factors contributed to this supply shortage, including:

Supplies of high-quality Northern White raw frac sand are limited to select areas, predominantly in western Wisconsin and limited areas of Minnesota and Illinois. The ability to obtain large contiguous reserves in these areas is a key constraint and can be an important supply consideration when assessing the economic viability of a potential raw frac sand facility. Further constraining the supply and throughput of Northern White raw frac sand is that not all of the large reserve mines have onsite excavation and processing capability. Additionally, much of the capital investment in Northern White raw frac sand mines was used to develop coarser deposits in western Wisconsin. With the shift to finer sands in the liquid and oil plays, many mines may not be economically viable as their ability to produce finer grades of sand may be limited.

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Pricing

We generally expect the price of raw frac sand to correlate with the level of drilling activity for oil and natural gas. The willingness of exploration and production companies to engage in new drilling is determined by a number of factors, the most important of which are the prevailing and projected prices of oil and natural gas, the cost to drill and operate a well, the availability and cost of capital and environmental and government regulations. We generally expect the level of drilling to correlate with long-term trends in commodity prices. Similarly, oil and natural gas production levels nationally and regionally generally tend to correlate with drilling activity.

Sand is sold on a contract basis or through spot market pricing. Long-term take-or-pay contracts reduce exposure to fluctuations in price and provide predictability of volumes and price over the contract term. By contrast, the spot market provides direct access to immediate prices, with accompanying exposure to price volatility and uncertainty. For sand producers operating under stable long-term contract structures, the spot market can offer an outlet to sell excess production at opportunistic times or during favorable market conditions.

How We Generate Revenue

We generate revenue by excavating and processing frac sand, which we sell to our customers under long-term price agreements or as spot sales at prevailing market rates. In some instances, revenues also include a charge for transportation services provided to customers. Our transportation revenue fluctuates based on a number of factors, including the volume of product transported and the distance between the plant and our customers.

As of December 31, 2017, our facility had annual nameplate production capacity of 3.3 million tons of raw frac sand. When market conditions are favorable, we look to enter into long-term take-or-pay contracts with our customers that are intended to mitigate our exposure to the potential price volatility of the spot market for raw frac sand and to enhance the stability of our cash flows. As of March 1, 2018, we have approximately 91.7% of our current annual nameplate production capacity contracted under seven long-term take-or-pay contracts. Each contract defines, among other commitments, the minimum volume of product that the customer is required to purchase per contract year and the minimum tonnage per grade, the volume of product that we are required to provide, the price that we will charge and that our customers will pay for each ton of contracted product, and certain remedies in the event either we or the customer fails to meet minimum requirements.

Our current contracts include agreed price ranges indexed to the price of crude oil (based upon the average WTI as listed on www.eia.doe.gov).  Our contracts contain mechanisms for upward (and in some cases downward) adjustment including: (i) annual percentage price escalators, or (ii) market factor increases, including a natural gas surcharge/reduction and/or a propane surcharge/reduction which are applied if the Average Natural Gas Price or the Average Quarterly Mont Belvieu TX Propane Spot Price, respectively, as listed by the U.S. Energy Information Administration, are above or below the applicable benchmark set in the contract for the preceding calendar quarter.

Our contracts generally provide that, if we are unable to deliver the contracted minimum volume of raw frac sand, the customer has the right to purchase replacement raw frac sand from alternative sources, provided that our inability to supply is not the result of an excusable delay. In the event that the price of replacement raw frac sand exceeds the contract price and our inability to supply the contracted minimum volume is not the result of an excusable delay, we are responsible for the price difference. At December 31, 2017, we had adequate levels of raw frac sand inventory on hand; therefore, the likelihood of any such penalties was considered remote.

Each of our contracts contains a minimum volume purchase requirement and, with the exception of one customer contract, provides for delivery of raw frac sand FCA at our Oakdale facility. The mesh size specifications in our contracts vary and include a mix of 20/40, 30/50, 40/70 and 100 mesh raw frac sand.  Certain of our contracts allow the customer to defer a portion of the annual minimum volume to future contract years, subject to a maximum deferral amount.

With respect to the take-or-pay contracts, if the customer is not allowed to make up deficiencies, we recognize revenues to the extent of the minimum contracted quantity, assuming payment is reasonably assured. If deficiencies can be made up, receipts in excess of actual sales are recognized as deferred revenues until production is actually taken or the right to make up deficiencies expires. For the years ended December 31, 2017, 2016 and 2015, we recognized $1.2 million, $20.9 million and 10.1 million in contractual minimum payments, respectively. As of December 31, 2017 and 2016, $0 million and $1.6 million of contractual minimum payments were recognized as deferred revenue, respectively.

Revenue is generally recognized FCA, payment made at the origination point at our facility, and title passes as the product is loaded into railcars hired by the customer or provided by us. Certain contracted and spot-rate customers have shipping terms of FCA, payment made at the destination, for which we recognize revenue when the sand is delivered.

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Costs of Conducting Our Business

The principal direct costs involved in operating our business are excavation, labor and utility costs.

We incurred excavation costs of $2.1 million, $1.9 million and $1.4 million during the years ended December 31, 2017, 2016 and 2015, respectively.

We incur excavation costs with respect to the excavation of sand and other materials from which we ultimately do not derive revenue. However, the ratio of rejected materials to total amounts excavated has been, and we believe will continue to be, in line with our expectations, given the extensive core sampling and other testing we undertook at the Oakdale facility. For more information regarding our reserves testing procedures, please read “Business—Our Assets and Operations—Our Reserves.”

Labor costs associated with employees at our processing facility represent the most significant cost of converting raw frac sand to finished product. We incurred labor costs of $9.3 million, $5.2 million and $4.8 million for the years ended December 31, 2017, 2016 and 2015, respectively.

We incur utility costs in connection with the operation of our processing facility, primarily electricity and natural gas, which are both susceptible to market fluctuations. We incurred utility costs of $5.8 million, $2.5 million and $2.6 million for the years ended December 31, 2017, 2016 and 2015, respectively. Our facilities require periodic scheduled maintenance to ensure efficient operation and to minimize downtime, which historically has not resulted in significant costs to us.

Direct excavation costs, processing costs, overhead allocation, depreciation and depletion are capitalized as a component of inventory and are reflected in cost of goods sold when inventory is sold.

On August 1, 2010, we entered into a consulting agreement related to the purchase of land with a third party, whereby he acted as an agent for us to obtain options to purchase certain identified real property in Wisconsin, as well as obtain permits and approvals necessary to open, construct and operate a sand mining and processing facility on such real property. In connection with this agreement, our mineral rights are subject to an aggregate non-participating royalty interest of $0.50 per ton sold of 70 mesh and coarser substrate.

Due to sustained freezing temperatures in our area of operation during winter months, we have historically halted the operation of our wet plant for approximately three to five months. As a result, we have excavated and washed sand in excess of current delivery requirements during the months when the wet plant was operational. This excess sand is placed in stockpiles that feed the dry plants and enable us to fill customer orders throughout the year without interruption. Our second wet plant facility, brought online in the fourth quarter of 2017, is in the process of being enclosed, allowing us to produce certain capacity during the winter months.

How We Evaluate Our Operations

Gross Profit and Production Costs

We market our raw frac sand production under long-term take-or-pay contracts that either have fixed prices for our production or market based prices for our production that fluctuate with the price of crude oil. Additionally, we sell sand on a spot basis at current prevailing spot market prices. When market conditions are favorable, we look to enter into long-term take-or-pay contracts with our customers that are intended to mitigate our exposure to the potential price volatility of the spot market for raw frac sand and to enhance the stability of our cash flows. As of March 1, 2018, we have approximately 91.7% of our current annual production capacity contracted under seven long-term take-or-pay contracts. Our revenues are generated from a combination of raw frac sand sales and minimum contractual payments we receive from our customers. Gross profit will primarily be affected by the price we are able to receive for the sale of our raw frac sand along with our minimum contractual payments made by our customers and our ability to control other direct and indirect costs associated with processing raw frac sand.

We also use production costs, which we define as costs of goods sold, excluding depreciation, depletion, accretion of asset retirement obligations and freight charges, to measure our financial performance. We believe production costs is a meaningful measure because it provides a measure of operating performance that is unaffected by historical cost basis. For a reconciliation of production costs to its most directly comparable financial measure calculated and presented in accordance with GAAP, please read “Note Regarding Non-GAAP Financial Measures.”

Note Regarding Non-GAAP Financial Measures

Production costs, EBITDA and Adjusted EBITDA are not financial measures presented in accordance with GAAP. We believe that the presentation of these non-GAAP financial measures will provide useful information to investors in assessing our financial condition and results of operations. Costs of goods sold is the GAAP measure most directly comparable to production costs and net

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income is the GAAP measure most directly comparable to EBITDA and Adjusted EBITDA. Our non-GAAP financial measures should not be considered as alternatives to the most directly comparable GAAP financial measure. Each of these non-GAAP financial measures has important limitations as analytical tools because they exclude some but not all items that affect the most directly comparable GAAP financial measures. You should not consider production costs, EBITDA or Adjusted EBITDA in isolation or as substitutes for an analysis of our results as reported under GAAP. Because production costs, EBITDA and Adjusted EBITDA may be defined differently by other companies in our industry, our definitions of these non-GAAP financial measures may not be comparable to similarly titled measures of other companies, thereby diminishing their utility.

EBITDA and Adjusted EBITDA

We define EBITDA as our net income, plus: (i) depreciation, depletion and amortization expense; (ii) income tax expense (benefit); (iii) interest expense; and (iv) franchise taxes. We define Adjusted EBITDA as EBITDA, plus: (i) gain or loss on sale of fixed assets or discontinued operations; (ii) integration and transition costs associated with specified transactions, including our IPO; (iii) equity compensation; (iv) development costs; (v) non-recurring cash charges related to restructuring, retention and other similar actions; (vi) earn-out and contingent consideration obligations; and (vii) non-cash charges and unusual or non-recurring charges. Adjusted EBITDA is used as a supplemental financial measure by management and by external users of our financial statements, such as investors and commercial banks, to assess:

We believe that our presentation of EBITDA and Adjusted EBITDA will provide useful information to investors in assessing our financial condition and results of operations. Net income is the GAAP measure most directly comparable to EBITDA and Adjusted EBITDA. EBITDA and Adjusted EBITDA should not be considered alternatives to net income presented in accordance with GAAP. Because EBITDA and Adjusted EBITDA may be defined differently by other companies in our industry, our definitions of EBITDA and Adjusted EBITDA may not be comparable to similarly titled measures of other companies, thereby diminishing their utility. The following table presents a reconciliation of EBITDA and Adjusted EBITDA to net income for each of the periods indicated.

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Production Costs

We also use production costs, which we define as costs of goods sold, excluding depreciation, depletion, accretion of asset retirement obligations and freight charges to measure our financial performance. Freight charges consist of shipping costs and railcar rental and storage expenses. Shipping costs consist of railway transportation costs to deliver products to customers. A portion of these freight charges are passed through to our customers and are, therefore, included in revenue. Railcar rental and storage expenses are associated with our long-term railcar operating agreements with certain customers. We believe production costs is a meaningful measure to management and external users of our financial statements, such as investors and commercial banks because it provides a measure of operating performance that is unaffected by historical cost basis. Cost of goods sold is the GAAP measure most directly comparable to production costs. Production costs should not be considered an alternative to cost of goods sold presented in accordance with GAAP. Because production costs may be defined differently by other companies in our industry, our definition of production costs may not be comparable to similarly titled measures of other companies, thereby diminishing its utility. The following table presents a reconciliation of production costs to cost of goods sold.

Factors Impacting Comparability of Our Financial Results

Our historical results of operations and cash flows are not indicative of results of operations and cash flows to be expected in the future, principally for the following reasons:

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Results of Operations

The following table summarizes our revenue and expenses for the periods indicated.

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

Revenue

Revenue was $137.2 million for the year ended December 31, 2017, during which we sold approximately 2,449,000 tons of sand. Revenue for the year ended December 31, 2016 was $59.2 million, during which we sold approximately 826,000 tons of sand. The increase in revenue is primarily attributable to improved market conditions and higher sales volumes (including spot sales) in the current year, partially offset by lower average selling prices due to reservation revenue being spread over a larger amount of contractual volumes sold in 2017 compared to 2016.

The key factors contributing to the increase in revenues for the year ended December 31, 2017 as compared to the year ended December 31, 2016 were as follows:

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Cost of Goods Sold and Production Costs

Cost of goods sold was $100.3 million and $26.6 million, or $40.96 and $32.30 per ton sold, for the years ended December 31, 2017 and 2016, respectively. Of this amount, production costs comprised $33.3 million and $12.6 million, or $13.61 and $15.22 per ton sold, and freight charges, which consist of shipping costs and railcar rental and storage expense, comprised $59.7 million and $7.9 million for the years ended December 31, 2017 and 2016, respectively. Cost of goods sold was approximately $73.7 million higher in 2017 compared to 2016 due to higher sales volumes which led to higher production costs and higher railcar rental expenses associated with this increased sales activity and additional depreciation expense. Freight expense also increased by approximately $50 million as a result of more in-basin sales and customer sales with pass-through freight. Depreciation, depletion and accretion included in cost of goods sold account for $7.3 million and $6.1 million, respectively, for the years ended December 31, 2017 and 2016. For the definition of production costs and a reconciliation to its most directly comparable financial measure calculated and presented in accordance with GAAP, please read “Note Regarding Non-GAAP Financial Measures”.

Gross Profit

Gross profit equals revenues less cost of goods sold. Gross profit was $36.9 million and $32.7 million for the years ended December 31, 2017 and 2016, respectively. The increase in gross profit was primarily due to increased sales volumes and higher reservation revenue as compared to the prior year, partially offset by higher cost of goods sold and lower shortfall revenue.

Operating Expenses

Operating expenses were $18.2 million and $12.3 million for the years ended December 31, 2017 and 2016, respectively. Operating expenses are comprised primarily of wages and benefits, professional services fees and other administrative expenses. Salaries, benefits and payroll taxes were $8.2 million and $7.4 million for the years ended December 31, 2017 and 2016, respectively. The approximately $0.8 million increase was due to additional employee headcount and stock compensation grants in 2017 as compared to 2016. Selling, general and administrative expenses increased by $5.0 million in 2017 compared to 2016 as a result of additional insurance, consulting and legal costs incurred as a publicly traded corporation as well as increased development activity.

Series A Preferred Stock and Other Interest Expense

We incurred $0.5 and $8.4 million of net interest expense during each of the years ended December 31, 2017 and 2016, respectively. Interest expense in 2017 was derived primarily from deferred finance fees and unused line fees for our existing revolving credit facility. Interest expense for 2016 was derived primarily from paid-in-kind interest on the Series A Preferred Stock as well as interest on our former revolving credit facility. Interest on the Series A Preferred Stock and our former revolving credit facility accounted for $5.6 million and $2.7 million, respectively, for the year ended December 31, 2016. On November 9, 2016, the Series A Preferred Stock was fully redeemed and the former revolving credit facility was paid in full and terminated using a portion of the proceeds from our IPO.

Other Income

Other income was $0.5 million and $8.9 million for the years ended December 31, 2017 and 2016, respectively. In 2016, we recognized other income of approximately $1.9 million related to the settlement of our unsecured bankruptcy claim with a former customer and $6.6 million related to the sale of our unsecured bankruptcy claim with the same customer.

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Income Tax (Benefit) Expense

Income tax benefit was $2.8 million for the year ended December 31, 2017 compared to an expense of $9.4 million for the year ended December 31, 2016. For the year ended December 31, 2017, our statutory tax rate and effective tax rate were approximately 35.0% and (15.0%), respectively. For the year ended December 31, 2016, our statutory tax rate and effective tax rate were approximately 35.0% and 48.0%, respectively. The computation of the 2017 effective tax rate includes modifications for share-based compensation, domestic manufacturing deduction, and state income tax credit among others. The computation for 2017 included the impact of depletion method change for tax purposes on our prior year returns. The effective rate was also impacted by tax reform signed into law in 2017, as indicated below.  The computation for 2016 also included modifications for non-deductible interest expense on the Series A Preferred Stock. The primary drivers of the difference between the effective rates in 2017 and 2016 was the full redemption of the Series A Preferred Stock in November 2016, the method of calculating depletion for tax purposes and tax reform. 

On December 22, 2017, the U.S. Tax Cuts and Jobs Act (the “Tax Reform Act”) was signed into law.  The Tax Reform Act significantly revised the U.S. corporate income tax regime by, among other things, lowering the U.S. corporate tax rate from 35% to 21% effective January 1, 2018, repealing the deduction for domestic production activities and implementing 100% direct expensing of certain non-residential property.  U.S. GAAP requires that the impact of tax legislation be recognized in the period in which the law was enacted.

As a result of the Tax Reform Act, we recorded a tax benefit of approximately $8.5 million due to a re-measurement of deferred tax assets and liabilities.  There are additional provisions in the Tax Reform Act that could impact us that will continue to be monitored as additional guidance is released.  The tax benefit represents provisional amounts and our current best estimates.  Any adjustments recorded to the provisional amounts through the first quarter of fiscal 2019 will be included in income from operations as an adjustment to tax expense.  The provisional amounts incorporate assumptions made based upon our current interpretation of the Tax Reform Act and may change as we receive additional clarification and implementation guidance.

Net Income and Adjusted EBITDA

Net income was $21.5 million for year ended December 31, 2017 compared to $10.4 million for the year ended December 31, 2016. Adjusted EBITDA was $30.6 million for the year ended December 31, 2017 compared to $37.8 million for the year ended December 31, 2016. The increase in net income was primarily due to higher volumes sold and higher reservation revenue, offset by lower shortfall revenue, increased salaries and employee headcount, and additional costs incurred as a result of being a publicly traded corporation. Additionally, net income was positively impacted by lower interest expense due to the full redemption of Series A Preferred Stock in November 2016, no debt outstanding on our existing credit facility and the income tax benefit recognized as a result of the Tax Reform Act. The decrease in Adjusted EBITDA primarily resulted from the decrease in shortfall revenue. For the definition of Adjusted EBITDA and a reconciliation to its most directly comparable financial measure calculated and presented in accordance with GAAP, please read “Note Regarding Non-GAAP Financial Measures.”

Year Ended December 31, 2016 Compared to the Year Ended December 31, 2015

Revenue

Revenue was $59.2 million for the year ended December 31, 2016, during which we sold approximately 826,000 tons of sand. Revenue for the year ended December 31, 2015 was $47.7 million, during which we sold approximately 751,000 tons of sand. Total revenue increased for the year ended December 31, 2016 as compared to the year ended December 31, 2015, due to higher sales volumes and higher average revenue per ton sold, which increased by approximately $8 as a result of other contractual terms, such as required reservation and shortfall payments.

The key factors contributing to the increase in revenues and increase in average revenue per ton for the year ended December 31, 2016 as compared to the year ended December 31, 2015 were as follows:

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Cost of Goods Sold and Production Costs

Cost of goods sold was $26.6 million and $21.0 million, or $32.30 and $27.97 per ton sold, for the years ended December 31, 2016 and 2015, respectively. Of this amount, production costs comprised $12.6 million and $10.1 million, or $15.22 and $13.47 per ton sold, and freight charges, which consist of shipping costs and railcar rental and storage expense, comprised $7.9 million and $6.0 million for the years ended December 31, 2016 and 2015, respectively. Cost of goods sold was approximately $5.6 million lower in 2016 compared to 2015 due to higher sales volumes, which led to higher production costs and higher railcar rental expenses, and additional depreciation expense.  Depreciation, depletion and accretion included in cost of goods sold account for $6.1 million and $4.9 million, respectively, for the years ended December 31, 2016 and 2015. For the definition of production costs and a reconciliation to its most directly comparable financial measure calculated and presented in accordance with GAAP, please read “Note Regarding Non-GAAP Financial Measures.”

Gross Profit

Gross profit equals revenues less cost of goods sold. Gross profit was $32.7 million and $26.7 million for the years ended December 31, 2016 and 2015, respectively.

Operating Expenses

Operating expenses were $12.3 million and $10.1 million for the years ended December 31, 2016 and 2015, respectively. Salaries, benefits and payroll taxes were $7.4 million and $5.1 million for the years ended December 31, 2016 and 2015, respectively, due to higher bonuses paid in 2016. Selling, general and administrative expenses decreased by $0.2 million in 2016 compared to 2015 due to higher costs incurred operating as a public company, offset by a decrease in development activity and professional costs incurred in 2015 related to our previous uncompleted initial public offering process.

Series A Preferred Stock and Other Interest Expense

We incurred $8.4 million and $7.8 of interest expense during the years ended December 31, 2016 and 2015, respectively. Interest expense in 2016 and 2015 was derived primarily from paid-in-kind interest on the Series A Preferred Stock as well as interest on our former revolving credit facility. Interest on the Series A Preferred Stock accounted for $5.6 million and $5.1 million of the expense for the years ended December 31, 2016 and 2015, respectively. Interest on our former revolving credit facility accounted for $2.7 million and $2.6 million, respectively, for the years ended December 31, 2016 and 2015. Additional items included in interest expense include the accretion of common stock issued and transaction costs incurred in conjunction with the September 2011 Securities Purchase Agreement, deferred financing fees, and interest incurred on capital leases. The paid-in-kind interest is added to the outstanding balance of the Preferred Stock. The Series A Preferred Stock was fully redeemed and our former revolving credit facility was fully repaid with proceeds of the IPO. No borrowings have been drawn against our existing revolving credit facility in 2016.

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Other Income

Other income was $8.9 million and $0.4 million for the years ended December 31, 2016 and 2015, respectively. In 2016, we recognized other income of approximately $1.9 million related to the settlement of our unsecured bankruptcy claim with a former customer and $6.6 million related to the sale of our unsecured bankruptcy claim with the same customer. Other income in 2015 primarily related to approximately $0.7 million railcar shortage fees offset by approximately $0.4 million loss on derivative.

Income Tax Expense

Income tax expense was $9.4 million for the year ended December 31, 2016 compared to $4.1 million for the year ended December 31, 2015. For the year ended December 31, 2016, our statutory tax rate and effective tax rate were approximately 35.0% and 48.0%, respectively. For the year ended December 31, 2015, our statutory tax rate and effective tax rate were approximately 35.0% and 45.0%, respectively. The difference in these tax rates for both 2016 and 2015 was primarily due to state income tax, non-deductible interest expense on the Preferred Stock costs associated with our initial public offering process.

Net Income and Adjusted EBITDA

Net income was $10.4 million for year ended December 31, 2016 compared to $5.0 million for the year ended December 31, 2015. Adjusted EBITDA was $37.8 million for the year ended December 31, 2016 compared to $23.9 million for the year ended December 31, 2015. The increase in net income and Adjusted EBITDA resulted from the increase in revenue and gross profit primarily due to higher volumes from increased exploration and production activity in the oil and natural gas industry in the second half of 2016 and higher contractual revenue in 2016 in comparison to 2015, as well as other income related to the settlement of a former customer’s bankruptcy claims. For the definition of Adjusted EBITDA and a reconciliation to its most directly comparable financial measure calculated and presented in accordance with GAAP, please read “Note Regarding Non-GAAP Financial Measures.”

Working Capital

Working capital is the amount by which current assets exceed current liabilities and is a measure of our ability to pay our liabilities as they become due.

The following table presents the components of our working capital as of December 31, 2017 compared to December 31, 2016.

Our working capital surplus was $38.2 million at December 31, 2017 compared to a working capital of $51.3 million at December 31, 2016. On February 7, 2017, we closed on an equity offering of 1,500 shares of our common stock, generating net proceeds of approximately $24.2 million. Our increased sales volumes in 2017 resulted in increased accounts receivable and unbilled receivables. As a result of the material ongoing capital expenditure projects, our cash and cash equivalents have decreased. Additionally, as a result of the capital expenditure projects and increased pass-through rail freight, accounts payables and accrued expenses have increased by $29.6 million.

Liquidity and Capital Resources

Sources of Liquidity

Prior to the IPO, our primary sources of liquidity were from funds generated through operations and our former revolving credit facility.

On November 9, 2016, we consummated the IPO of 11,700 shares of common stock at a price of $11.00 per share, generating net proceeds to us of $128.7 million before underwriting discounts and expenses. We used a portion of the net proceeds from the IPO to redeem all of our outstanding Series A Preferred Stock and to repay the outstanding indebtedness under our former revolving credit facility, which was terminated. We intend to use the remaining net proceeds for general corporate purposes.

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On November 23, 2016, the underwriters exercised in full their option to purchase additional shares of common stock from us and the selling shareholders.  On November 29, 2016, we consummated the sale of 878 shares of common stock to the underwriters pursuant to the underwriters’ exercise of their over-allotment option at a price of $11.00 per share, generating proceeds to us of $9.7 million before underwriting discounts and expenses. We received no proceeds from the sale of common stock to the underwriters by the selling shareholders.  We intend to use the net proceeds of the IPO for general corporate purposes.

On February 1, 2017, we consummated a follow-on offering and sale of 1,500 shares of common stock at a price of $17.50 per share, generating net proceeds to us of $24.3 million before underwriting discounts and expenses. We used the proceeds from this offering for capital projects and general corporate services. The offering closed on February 7, 2017. Additionally, certain of our stockholders sold 4,450 shares of common stock at a price of $17.50 per share. We received no proceeds from the sale of common stock by such stockholders.

On February 10, 2017, the underwriters exercised in full their option to purchase additional shares of common stock from certain of our stockholders.  On February 15, 2017, such stockholders consummated the sale of 893 shares of common stock to the underwriters pursuant to the underwriters’ exercise of their over-allotment option at a price of $17.50 per share. We received no proceeds from the sale of common stock to the underwriters by such stockholders.  

Going forward, we expect our primary source of liquidity to be funded through cash flow generated from operations and borrowings under our existing credit facility.

Liquidity

The following table sets forth a summary of our cash flows for the periods indicated:

Summary Cash Flows for the Years Ended December 31, 2017, 2016 and 2015:

Cash Provided by Operating Activities

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

Net cash provided by operating activities was $15.6 million and $26.7 million for the years ended December 31, 2017 and 2016, respectively. Operating cash flows include net income of $21.5 million and $10.4 million in net earnings generated from the sale of frac sand to our customers in the years ended December 31, 2017 and 2016, respectively, offset by production costs, general and administrative expenses and cash interest expense, adjusted for changes in working capital to the extent they are positive or negative.

The increase in accounts receivable from $0.3 million in 2016 to $18.8 million in 2017 resulted from the increase in sales volumes and the increase of customers to which we charge freight. The increase in accounts payable and accrued expenses is due to pass-through rail freight and ongoing capital expenditure projects during 2017.

Year Ended December 31, 2016 Compared to the Year Ended December 31, 2015

Net cash provided by operating activities was $26.7 million and $30.7 million for the years ended December 31, 2016 and 2015, respectively. Operating cash flows include net income of $10.4 million and $5.0 million in net earnings generated from the sale of frac sand to our customers in the years ended December 31, 2016 and 2015, respectively, offset by production costs, general and administrative expenses and cash interest expense, adjusted for changes in working capital to the extent they are positive or negative.

Cash Used In Investing Activities

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

Net cash used in investing activities was $51.1 million for the year ended December 31, 2017 compared with $2.5 million for the year ended December 31, 2016. The $48.6 million increase was primarily the result of an increase in capital expenditures related primarily to the expansion of our processing facilities in Oakdale, Wisconsin.

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Year Ended December 31, 2016 Compared to the Year Ended December 31, 2015

Net cash used in investing activities was $2.5 million for the year ended December 31, 2016 compared with $29.4 million for the year ended December 31, 2015. The $26.9 million decrease was primarily the result of a decrease in capital expenditures.

Cash Provided by Financing Activities

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

Net cash provided by financing activities was $23.2 million for the year ended December 31, 2017, which included net proceeds from equity issuance of $24.2 million, $0.6 million in payments on equipment financing obligations and notes payable, $0.2 million on deferred financing and amendment costs and $0.1 million in treasury stock purchases.

Net cash provided by financing activities was $19.4 million for the year ended December 31, 2016, which included net proceeds from equity issuance of $127.3 million, offset by net repayments of $64.2 million under our former revolving credit facility, $40.3 million of Series A Preferred Stock, $1.3 million of repayments on long-term debt, $0.4 million in payments on equipment financing obligations, $1.2 million on loan amendment fees and $0.4 million in treasury stock purchases.

Year Ended December 31, 2016 Compared to the Year Ended December 31, 2015

Net cash provided by financing activities was $19.4 million for the year ended December 31, 2016, which included net proceeds from equity issuance of $127.3 million, offset by net repayments of $64.2 million under our former revolving credit facility, $40.3 million of Series A Preferred Stock, $1.3 million of repayments on long-term debt, $0.4 million in payments on equipment financing obligations, $1.2 million on loan amendment fees and $0.4 million in treasury stock purchases.

Net cash provided by financing activities was $1.8 million for the year ended December 31, 2015, which included net borrowings of $3.2 million under our existing revolving credit facility, offset by $0.5 million of repayments on long-term debt, $0.4 million in payments on equipment financing obligations, $0.4 million on loan amendment fees and $0.1 million in treasury stock purchases.

Credit Facilities

Our Credit Facility and Other Arrangements

Below is a description of our former and existing revolving credit facilities and other financing arrangements.

Former Revolving Credit Agreement

On March 28, 2014, we entered into a $72.5 million revolving credit and security agreement (“Credit Agreement”) with PNC Bank, National Association, as administrative agent and collateral agent (the “Credit Agreement”). The revolving credit facility under the Credit Agreement had a maturity date of March 28, 2019. We refer to this facility as the former revolving credit facility.

On November 9, 2016, the former revolving credit facility was paid in full and terminated using a portion of the proceeds from the IPO.

Existing Revolving Credit Facility

On December 8, 2016, we entered into a $45 million 3-year senior secured Revolving Credit Facility (the “Facility”) with Jefferies Finance LLC as administrative and collateral agent. Substantially all of our assets are pledged as collateral under the Credit Agreement. The Facility expires on December 8, 2019 and contains various reporting requirements, negative covenants, restrictive provisions and requires maintenance of financial covenants, including a fixed charge coverage ratio and a leverage ratio (each as defined in the credit agreement).

Capital Requirements

As of December 31, 2017, we had commitments related to our Oakdale facility as well as future expansion projects of approximately $35.1 million. We expect to incur approximately $85 to $95 million during 2018 in expansion and replacement capital expenditures. Expansion capital expenditures are anticipated to support incremental growth and efficiency initiatives. These projects are expected to provide efficiencies in our plant operations and improve our logistics capabilities to further position us to capitalize upon growth opportunities that we anticipate will continue to develop with both current and potential new customers. We expect to fund these expansion capital expenditures with cash from operations, cash from our previous equity offerings and availability under our $45 million revolver.  

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Environmental Matters

We are subject to various federal, state and local laws and regulations governing, among other things, hazardous materials, air and water emissions, environmental contamination and reclamation and the protection of the environment and natural resources. We have made, and expect to make in the future, expenditures to comply with such laws and regulations, but cannot predict the full amount of such future expenditures.

Off-Balance Sheet Arrangements

At December 31, 2017 and December 31, 2016, we had outstanding performance bonds of $8.6 million and $8.3 million, respectively.

Seasonality

Our business is affected to some extent by seasonal fluctuations in weather that impact the production levels at our wet processing plant. While our dry plants are able to process finished product volumes evenly throughout the year, our excavation and our wet sand processing activities are limited to non-winter months. As a consequence, we experience lower production operating costs in the first and fourth quarter of each calendar year. We may also sell raw frac sand for use in oil and natural gas producing basins where severe weather conditions may curtail drilling activities and, as a result, our sales volumes to those areas may be reduced during such severe weather periods.

Customer Concentration

For the year ended December 31, 2017, sales to Rice Energy, Liberty, Weatherford, and US Well Services accounted for 27.1%, 20.6%, 13.7%, and 10.2%, respectively, of total revenue. For the year ended December 31, 2016, sales to EOG Resources, Weatherford, US Well Services and C&J Energy Services accounted for 37.5%, 25.2%, 22.4% and 10.8%, respectively, of total revenue. For the year ended December 31, 2015, sales to EOG Resources, US Well Services, Weatherford and Archer Pressure Pumping accounted for 35.0%, 24.6%, 18.4% and 15.8%, respectively, of total revenue.

Contractual Obligations

The following table presents our contractual obligations and other commitments as of December 31, 2017.

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Recent Accounting Pronouncements

In August 2017, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2017-12 “Derivatives and Hedging (Topic 815) Targeted Improvements to Accounting for Hedging Activities”. ASU 2017-12 eliminates the requirement to separately measure and report hedge ineffectiveness and generally requires the entire change in the fair value of a hedging instrument to be presented in the same income statement line as the hedged item. The guidance also eases certain documentation and assessment requirements and modifies the accounting for components excluded from the assessment of hedge effectiveness. The guidance is effective for the Company beginning after December 15, 2018, although early adoption is permitted. The Company is currently evaluating the effects of ASU 2017-12 on its consolidated financial statements.

In August 2016, the FASB issued ASU 2016-15, “Statement of Cash Flows (Topic 230) Classification of Certain Cash Receipts and Cash Payments” (“ASU 2016-15”). ASU 2016-15 eliminates the diversity in practice related to the classification of certain cash receipts and payments for debt prepayment or extinguishment costs, the maturing of a zero-coupon bond, the settlement of contingent liabilities arising from a business combination, proceeds from insurance settlements, distributions from certain equity method investees and beneficial interests obtained in a financial asset securitization. ASU 2016-15 designates the appropriate cash flow classification, including requirements to allocate certain components of these cash receipts and payments among operating, investing and financing activities. The guidance is effective for the Company beginning after December 15, 2017, although early adoption is permitted. Although the Company is still in the process of assessing the impact of the adoption of ASU 2016-15, it does not currently anticipate a material impact on its financial statements.

In February 2016, the FASB issued ASU 2016-02, “Leases (ASC 842)” (“ASU 2016-02”), which replaces the existing guidance in ASC 840, “Leases”. ASC 842 requires lessees to recognize most leases on their balance sheets as lease liabilities with corresponding right of use assets. The new lease standard does not substantially change lessor accounting. The new standard is effective for interim and annual reporting periods beginning after December 15, 2018, with early adoption permitted. The Company is currently in the process of evaluating the impact of the adoption on its consolidated financial statements.

In May 2014, the FASB issued ASU 2014-09, “Revenue from Contracts with Customers” (“ASU 2014-09”). The objective of ASU 2014-09 is to establish a single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and will supersede most of the existing revenue recognition guidance, including industry specific guidance. The core principle of ASU 2014-09 is that an entity recognizes revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. In applying the new guidance, an entity will: (1) identify the contract(s) with a customer; (2) identify the performance obligations in the contract; (3) determine the transaction price; (4) allocate the transaction price to the contract’s performance obligations; and (5) recognize revenue when (or as) the entity satisfies a performance obligation. ASU 2014-09 applies to all contracts with customers except those that are within the scope of other topics in the FASB Accounting Standards Codification. In April and May 2016, the FASB issued ASU 2016-10, “Revenue from Contracts with Customers – Identifying Performance Obligations and Licensing”, ASU 2016-11, “Revenue Recognition and Derivatives and Hedging – Recession of SEC Guidance”, ASU 2016-12, “Revenue from Contracts with Customers – Narrow-Scope Improvements and Practical Expedients”, and ASU 2016-20, “Technical Corrections and Improvements to Topic 606, Revenue from Contracts with Customers”.  These ASUs each affect the guidance of the new revenue recognition standard in ASU 2014-09 and related subsequent ASUs. The new guidance is effective for annual reporting periods (including interim periods within those periods) beginning after December 15, 2017 for public companies. Early adoption is only permitted as of annual reporting periods beginning after December 15, 2016. Entities have the option of using either a full retrospective or modified approach to adopt ASU 2014-09.

On January 1, 2018, we adopted the new accounting standard ASC 606, “Revenue from Contracts with Customers” and all the related amendments (“ASC 606”) to all contracts which were not completed or expired as of January 1, 2018 using the modified retrospective method. We will recognize the cumulative effect of initially applying the new revenue standard as an adjustment to the opening balance of retained earnings. Results for reporting periods beginning after January 1, 2018 will be presented under ASC 606, while the comparative information will not be restated and will continue to be reported under the accounting standards in effect for those periods. We expect the impact of the adoption of the new standard to be immaterial to our revenue and net income on an ongoing basis.

With the adoption of the standard, the consolidated financial statements will be supplemented by new disclosure requirements. Areas of focus and updated presentation requirements include disclosures surrounding contracts with customers, disaggregation of revenue, contract balances, performance obligations, significant judgements used in the application of the guidance and transaction price allocation to remaining performance obligations.

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Revenue Recognition

Revenues are recognized when control of the promised goods or services is transferred to our customers, the amount of which reflects the consideration the Company expects to be entitled to in exchange for those goods or services.

Sand Sales Revenue

The Company derives its revenue by mining and processing sand. Its revenues are primarily a function of the price per ton realized and the volumes sold. The Company’s sales are generally free carrier (“FCA”), payment made at the origination point at the Company’s facility, title passes as the product is loaded into railcars hired by the customer or provided by us, and revenue is recognized when title transfers at the Company’s facility. Certain spot-rate customers have shipping terms of FCA; the Company recognizes this revenue when the sand is received at the destination.

Prices under these agreements are generally indexed to the Average Cushing Oklahoma WTI Spot Prices and contain provisions allowing for adjustments including: (i) annual percentage price increases; or (ii) market factor increases (or in some cases decreases), including a natural gas surcharge/reduction and a propane surcharge/reduction which are applied if the Average Natural Gas Price or the Average Quarterly Mont Belvieu TX Propane Spot Price, respectively, as listed by the U.S. Energy Information Administration, are above or below the applicable benchmark set in the contract for the preceding calendar quarter.

Reservation Charges

The Company requires certain customers to pay a fixed-price monthly reservation charge based on a minimum contractual volume over the remaining life of their contract, which may be applied as a per ton credit to the sales price up to a certain contractually specified monthly volume or credited against any applicable shortfall payments. 

Shortfall Payments

The Company’s shortfall revenues are based on negotiated contract terms and are recognized when rights of use are expired. The Company recognizes revenue to the extent of the unfulfilled minimum contracted quantity at the shortfall price per ton as stated in the contract once payment is received or probable.

Railcar Rental

Railcar rentals consists of revenue derived from the leasing of the Company’s railcars to customers under long-term contracts or on an as-used basis. Based on the customer contract, the Company either recognizes revenue on the leasing of railcars based on when the terms of the agreement state that the railcar is available to the customer for use, or based on a specified price per ton shipped. The Company recognizes revenue from leasing in accordance with ASC 840, as leasing revenue does not meet the criteria of ASC 606.

Transportation Revenue

Transportation revenue consists of primarily pass-through railway transportation and revenue to deliver products to customers. The Company’s transportation revenue fluctuates based on many factors, including the volume of product it transports and the distance between its plant and customers.

Contract Balances

The timing of revenue recognition, billings and cash collections results in billed accounts receivable, unbilled receivables, and deferred revenue on the consolidated balance sheet. For the Company’s sand sales, amounts are billed as sand is loaded on the railcars to fill customer orders for free carrier origination point sales or when sand is received at the destination for free carrier destination point sales and recorded as accounts receivable. For the Company’s freight revenue, amounts billed depend on the shipping terms and are recorded as receivables accordingly. Generally, billing occurs subsequent to revenue recognition, resulting in unbilled receivables. In addition, the Company sometimes receives shortfall and reservation payments from its customers and recognizes the revenue once the rights of use are expired. Changes in the contract asset and liability balances during the year ended December 31, 2017 were not materially impacted by any other factors.

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Deferred Revenues

The Company receives advance payments from certain customers in order to secure and procure a reliable provision and delivery of product. The Company classifies such advances as current or noncurrent liabilities depending upon the anticipated timing of delivery of the supplied product. Revenue is recognized upon the delivery of the product.

The Company may receive an advance payment from a customer, based on the terms of the customer’s long-term contract, for a certain volume of product to be delivered. Revenue is recognized as product is delivered and the deferred revenue is reduced.

Revenue recognized for the year ended December 31, 2017 that was included in the contract liability balance at the beginning of the year was $1.6 million.

Performance Obligations

A performance obligation is a promise in a contract to transfer a distinct good or service to the customer, and is the unit of account in accordance with ASC 606. A contract’s transaction price is allocated to each distinct performance obligation and recognized as revenue when, or as, the performance obligation is satisfied.  Generally, the Company’s contracts include a single performance obligation that is separately identifiable, and therefore, distinct. Under ASC 606, the allocation of transaction price is not necessary if only one performance obligation is identified. We expect to recognize approximately 42% of this remaining performance obligation as revenue throughout the remainder of 2018, and the remaining 58% by 2021.

Revenue from sand sales are recognized at a point in time, either upon shipment or upon delivery, and accounted for 37% of our revenue for the year ended December 31, 2017.  Revenue from reservation charges and shortfall revenues are recognized at a point in time, when the right of use expires, and accounted for 22% and 1% of our revenue for the year ended December 31, 2017. Revenue from railcar rental and transportation is recognized at a point in time, upon shipment, and accounted for 5% and 35% of our revenue for the year ended December 31, 2017.

Significant Judgments

Accounting for long-term contracts involves the use of various techniques to estimate total contract revenue, costs and satisfaction of performance obligation. The Company satisfies its performance obligation and subsequently recognizes revenue, at a point in time, upon shipment of the products as the customer obtains control over the goods once the sand is loaded into the railcars or sand is delivered to the customer’s destination. In the case of frac sand being delivered to customers, the transaction price is variable in nature and is directly tied to the Average Cushing Oklahoma WTI Spot Prices per barrel. There were no changes to the significant judgments used by the Company to determine the timing of satisfaction of the performance obligation under ASC 606.

Costs to Obtain or Fulfill Contract

The Company’s incremental cost to fulfill or obtain contracts with customers primarily consist of commissions and legal costs. Under take-or-pay contracts, the Company provides sales team members with commissions at set per ton prices. These commissions are paid on a monthly basis, when and if the sand is taken by the customer. Because sales associates receive commissions when orders are fulfilled, the Company did not record any assets for commissions at December 31, 2017. The Company also incurs legal costs relating to the drafting and negotiating of a contract with select customers. Because these costs do not directly relate to the future ability to perform the contract, there were no legal costs capitalized as of December 31, 2017. The Company did not record amortization of costs incurred to obtain the contract or any impairment losses for the period ending December 31, 2017.

New and Revised Financial Accounting Standards

We qualify as an “emerging growth company” pursuant to the provisions of the JOBS Act, enacted on April 5, 2012. Section 102 of the JOBS Act provides that an “emerging growth company” can take advantage of the extended transition period provided in Section 7(a)(2)(B) of the Securities Act for complying with new or revised accounting standards. However, we are choosing to “opt out” of such extended transition period, and as a result, we will comply with new or revised accounting standards on the relevant dates on which adoption of such standards is required for non-emerging growth companies. Our election to “opt-out” of the extended transition period is irrevocable.

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Critical Accounting Policies and Estimates

The discussion and analysis of our financial condition and results of operations is based on our consolidated financial statements, which have been prepared in accordance with accounting principles generally acceptable in the United States of America. The preparation of these financial statements requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the dates of the financial statements and the reported revenues and expenses during the reporting periods. We evaluate these estimates and assumptions on an ongoing basis and base our estimates on historical experience, current conditions and various other assumptions that we believe to be reasonable under the circumstances. The results of these estimates form the basis for making judgments about the carrying values of assets and liabilities as well as identifying and assessing the accounting treatment with respect to commitments and contingencies. Our actual results may materially differ from these estimates.

Listed below are the accounting policies we believe are critical to our financial statements due to the degree of uncertainty regarding the estimates or assumptions involved, and that we believe are critical to the understanding of our operations.

Revenue Recognition

We recognize revenue when persuasive evidence of an arrangement exists, delivery of products has occurred, the sales price charged is fixed or determinable, collectability is reasonably assured, and the risk of loss is transferred to the customer. This generally means that sales are FCA, payment made at the origination point at our facility, and title passes as the product is loaded into railcars hired by the customer or provided by us. Certain spot-rate customers have shipping terms of FCA, payment made at the destination; and we recognize this revenue when the sand is received at the destination.

We derive our revenue by mining and processing sand that our customers purchase for various uses. Our revenues are primarily a function of the price per ton realized and the volumes sold. In some instances, our revenues also include transportation costs we charge to our customers, a monthly charge to reserve sand capacity and shortfall payments due from customers for minimum volume commitments. Our transportation revenue fluctuates based on a number of factors, including the volume of product we transport and the distance between our plant and our customers. Our reservation and shortfall revenue fluctuates based on negotiated contract terms.

We sell a limited amount of product under short-term price agreements or at prevailing market rates. The majority of our revenues are realized through long-term take-or-pay contracts. The expiration dates of these contracts range from 2019 through 2020. These agreements define, among other commitments, the volume of product that our customers must purchase, the volume of product that we must provide and the price that we will charge and that our customers will pay for each ton of contracted product. Prices under these agreements are generally indexed to WTI and subject to upward or downward adjustment, based upon: (i) annual percentage price increases; or (ii) market factor increases, including a natural gas surcharge/reduction and a propane surcharge/reduction which are applied if the Average Natural Gas Price or the Average Quarterly Mont Belvieu TX Propane Spot Price, respectively, as listed by the U.S. Energy Information Administration, are above the benchmark set in the contract for the preceding calendar quarter. As a result, our realized prices may not grow at rates consistent with broader industry pricing. For example, during periods of rapid price growth, our realized prices may grow more slowly than those of competitors, and during periods of price decline, our realized prices may outperform industry averages. With respect to the take-or-pay arrangements, if the customer is not allowed to make up deficiencies, we recognize revenues to the extent of the minimum contracted quantity, assuming payment is reasonably assured. Such revenue is generally recognized either quarterly or at the end of a customer contract year rather than ratably over the respective contract year. If deficiencies can be made up, receipts in excess of actual sales are recognized as deferred revenues until production is actually taken or the right to make up deficiencies expires.

Asset Retirement Obligation

We estimate the future cost of dismantling, restoring and reclaiming operating excavation sites and related facilities in accordance with federal, state and local regulatory requirements and recognize reclamation obligations when extraction occurs and record them as liabilities at estimated fair value. In addition, a corresponding increase in the carrying amount of the related asset is recorded and depreciated over such asset’s useful life or the estimated number of years of extraction. The reclamation liability is accreted to expense over the estimated productive life of the related asset and is subject to adjustments to reflect changes in value resulting from the passage of time and revisions to the estimates of either the timing or amount of the reclamation costs. Changes in estimates at inactive mines or mining areas are reflected in earnings in the period an estimate is revised. If the asset retirement obligation is settled for more or less than the carrying amount of the liability, a loss or gain will be recognized, respectively.

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Inventory Valuation

Sand inventory is stated at the lower of cost or net realizable value using the average cost method. Costs applied to inventory include direct excavation costs, processing costs, overhead allocation, depreciation and depletion. Stockpile tonnages are calculated by measuring the number of tons added and removed from the stockpile. Tonnages are verified periodically by an independent surveyor. Costs are calculated on a per ton basis and are applied to the stockpiles based on the number of tons in the stockpile.

Spare parts inventory includes critical spare parts. We account for spare parts on a first in first out basis, and value the inventory at the lower of cost or net realizable value.

Depletion

We amortize the cost to acquire land and mineral rights using a units-of-production method, based on the total estimated reserves and tonnage extracted each period.

Impairment of Long-Lived Assets

We periodically evaluate whether current events or circumstances indicate that the carrying value of our assets may not be recoverable. If circumstances indicate that the carrying value may not be recoverable, we estimate future undiscounted net cash (without interest charges), estimated future sales prices (considering historical and current prices, price trends and related factors) and anticipated operating costs and capital expenditures. We record a reduction in the carrying value of our long-lived assets if the undiscounted cash flows are less than the carrying value of the assets.

Our estimates of prices, recoverable proven reserves and operating and capital costs are subject to certain risks and uncertainties which may affect the recoverability of our long-lived assets. Although we have made our best estimate of these factors based on current conditions, it is reasonably possible that changes could occur, which could adversely affect our estimate of the net cash flows expected to be generated from our operating property. No impairment charges were recorded during the years ended December 31, 2017, 2016 and 2015.

Income Taxes

Under the balance sheet approach to provide for income taxes, we recognize deferred tax assets and liabilities for the expected future tax consequences of net operating loss carryforwards and temporary differences between the carrying amounts and the tax bases of assets and liabilities. In assessing the realizability of deferred tax assets, we consider whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the period in which those temporary differences become deductible. If we determine it is more likely than not that we will not be able to realize the benefits of the deductible temporary differences, we record a valuation against the net deferred tax asset.

We recognize the impact of uncertain tax positions at the largest amount that, in our judgment, is more-likely-than-not to be required to be recognized upon examination by a taxing authority.

Stock-Based Compensation

Stock-based compensation expense is recorded based upon the fair value of the award at grant date. Such costs are recognized as expense over the corresponding requisite service period. The fair value of the awards granted was calculated based on a weighted analysis of (i) publicly-traded companies in a similar line of business to us (market comparable method) and (ii) our discounted cash flows. The application of this valuation model involves inputs and assumptions that are judgmental and highly sensitive in the valuation of incentive awards, which affects compensation expense related to these awards. These inputs and assumptions include the value of a share of our common stock.

Prior to our initial public offering, we used a combination of the guideline company approach and a discounted cash flow analysis to determine the fair value of our stock. The key assumptions in this estimate included our projections of future cash flows, company-specific cost of capital used as a discount rate, lack of marketability discount, and qualitative factors to compare us to comparable guideline companies. During 2016, factors that contributed to changes in the underlying value of our stock included the continued market challenges and corresponding decline in oil and natural gas drilling activity, changes to future cash flows projected from the expansion of capacity, product mix, including mix of finer grade versus coarser grade sand, and other factors. As our operations are highly dependent on sales to the oil and gas industry, the market conditions for this industry had a high degree of impact on the company’s value.

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Once our shares became publicly traded, we began using the actual market price of our shares as the grant date fair value for restricted stock awards, and we no longer estimate the value of the shares underlying these stock-based awards.

The following is a summary of the restricted stock awards granted and the related grant date fair value in the years ended December 31, 2017, 2016 and 2015

During March 2016, we issued approximately 161 shares of restricted stock under our 2012 Equity Incentive Plan. These restricted stock awards consist of 50% service-based vesting over 4 years and 50% performance-based vesting upon the achievement of certain performance conditions.  The performance-based shares vested in December 2016 in connection with our common stock being actively traded on a national securities exchange at an aggregate market value in excess of $300 million over 20 consecutive trading days.

In connection with our initial public offering, we adopted a 2016 Omnibus Incentive Plan. Through December 31, 2017, we have issued approximately 352 shares under our 2016 Omnibus Incentive Plan.

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Item 7A. – Quantitative and Qualitative Disclosures About Market Risk

Market risk is the risk of loss arising from adverse changes in market rates and prices. Historically, our risks have been predominantly related to potential changes in the fair value of our long-term debt due to fluctuations in applicable market interest rates. Going forward our market risk exposure generally will be limited to those risks that arise in the normal course of business, as we do not engage in speculative, non-operating transactions, nor do we utilize financial instruments or derivative instruments for trading purposes. We do not believe that inflation has a material impact on our financial position or results of operations during periods covered by the financial statements included in this filing.

Commodity Price Risk

The market for proppant is indirectly exposed to fluctuations in the prices of crude oil and natural gas to the extent such fluctuations impact drilling and completion activity levels and thus impact the activity levels of our customers in the oilfield services and exploration and production industries. However, because we generate the substantial majority of our revenues under long-term take-or-pay contracts, we believe we have limited direct exposure to short-term fluctuations in the prices of crude oil and natural gas. We do not currently intend to hedge our indirect exposure to commodity price risk.

Interest Rate Risk

As of December 31, 2017, we had $0 outstanding under our existing revolving credit facility, which bears interest at our option at either:

On November 9, 2016, our former revolving credit facility was paid in full and terminated using a portion of the proceeds from the IPO, and was replaced with a facility with similar interest rate risk.

On December 8, 2016, we entered into the $45 million Facility with Jefferies Finance LLC as administrative and collateral agent. The Facility expires on December 8, 2019 and contains various reporting requirements, negative covenants, restrictive provisions and requires maintenance of financial covenants, including a fixed charge coverage ratio and a leverage ratio. As of December 31, 2017, there were no amounts outstanding under the Facility.

Credit Risk

Substantially all of our revenue for the year ended December 31, 2017 was generated through long-term take-or-pay contracts with six customers. Our customers are oil and natural gas producers and oilfield service providers, all of which have been negatively impacted by the recent downturn in activity in the oil and natural gas industry. This concentration of counterparties operating in a single industry may increase our overall exposure to credit risk, in that the counterparties may be similarly affected by changes in economic, regulatory or other conditions. If a customer defaults or if any of our contracts expires in accordance with its terms, and we are unable to renew or replace these contracts, our gross profit and cash flows may be adversely affected.

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Item 8. – Financial Statements and Supplementary Data

The following Consolidated Financial Statements are filed as part of this Annual Report on Form 10-K:

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Report of Independent Registered Public Accounting Firm

Board of Directors and Shareholders

Smart Sand, Inc.

Opinion on the financial statements

We have audited the accompanying consolidated balance sheets of Smart Sand, Inc. (a Delaware corporation) (and subsidiaries) (the “Company”) as of December 31, 2017 and 2016, the related consolidated statements of operations, changes in shareholders’ equity (deficit), and cash flows for each of the three years in the period ended December 31, 2017, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2017 and 2016, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017, in conformity with accounting principles generally accepted in the United States of America.

Basis for opinion

These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ GRANT THORNTON LLP

We have served as the Company’s auditor since 2014.

Philadelphia, Pennsylvania

March 15, 2018

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SMART SAND, INC.

CONSOLIDATED BALANCE SHEETS

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

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SMART SAND, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS