Annual Report (10-k)

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

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

For the fiscal year ended December 31, 2017

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

For the transition period from to

Commission File No. 001-35912

EMERGE ENERGY SERVICES LP

(Exact name of registrant as specified in its charter)



Delaware		90-0832937
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

5600 Clearfork Main Street, Suite 400, Fort Worth, Texas 76109		(817) 618-4020
(Address of principal executive offices)		(Registrant’s telephone number, including area code)

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



Title of Each Class		Name of Each Exchange On Which Registered
Common Units Representing Limited Partner Interests		New York Stock Exchange

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

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. o Yes ý No

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. o Yes ý No

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. ý Yes o 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). ý Yes o No

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K 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. o

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)



Large-Accelerated Filer o	Accelerated Filer x	Non-Accelerated Filer o	Smaller Reporting Company o	Emerging Growth Company o

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. o Yes o No

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

As of June 30, 2017, the last business day of the registrant's second fiscal quarter of 2017 , the aggregate market value of the registrant's common units held by non-affiliates of the registrant was $193,148,316 based on the closing price as reported on the New York Stock Exchange composite tape on that date.

As of February 22, 2018 , 31,006,173 common units were outstanding.

DOCUMENTS INCORPORATED BY REFERENCE: None

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		Page
	PART I



Item 1 .	Business	1

Item 1A.	Risk Factors	15

Item 1B.	Unresolved Staff Comments	35

Item 2.	Properties	35

Item 3.	Legal Proceedings	35

Item 4.	Mine Safety Disclosures	36

	PART II
Item 5 .	Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities	37

Item 6.	Selected Financial Data	39

Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	46

Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	60

Item 8.	Financial Statements and Supplementary Data	61

Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	89

Item 9A.	Controls and Procedures	89

Item 9B.	Other Information	91
PART III

Item 10.	Directors, Executive Officers and Corporate Governance	91

Item 11.	Compensation Discussion and Analysis	96

Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters	107

Item 13.	Certain Relationships and Related Transactions, and Director Independence	109

Item 14.	Principal Accounting Fees and Services	110
PART IV
Item 15.	Exhibits and Financial Statement Schedules	111
Item 16.	Form 10-K Summary	111

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CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS

Certain statements and information in this Annual Report on Form 10-K may constitute “forward-looking statements.” The words “believe,” “expect,” “anticipate,” “plan,” “intend,” “foresee,” “should,” “would,” “could” or other similar expressions are intended to identify forward-looking statements, which are generally not historical in nature. These forward-looking statements are based on our current expectations and beliefs concerning future developments and their potential effect on us. While management believes that these forward-looking statements are reasonable as and when made, there can be no assurance that future developments affecting us will be those that we anticipate. All comments concerning our expectations for future revenues and operating results are based on our forecasts for our existing operations and do not include the potential impact of any future acquisitions. Our forward-looking statements involve significant risks and uncertainties (some of which are beyond our control) and assumptions that could cause actual results to differ materially from our historical experience and our present expectations or projections. Known material factors that could cause our actual results to differ from those in the forward-looking statements are those described in Part I, Item 1A. Risk Factors.

Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. We undertake no obligation to publicly update or revise any forward-looking statements after the date they are made, whether as a result of new information, future events or otherwise.

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GLOSSARY OF SELECTED TERMS

16/30 frac sand: Sand that passes through a sieve with 16 holes per linear inch (16 mesh) and is retained by a sieve with 30 holes per linear inch (30 mesh).

20/40 frac sand: Sand that passes through a sieve with 20 holes per linear inch (20 mesh) and is retained by a sieve with 40 holes per linear inch (40 mesh).

30/50 frac sand: Sand that passes through a sieve with 30 holes per linear inch (30 mesh) and is retained by a sieve with 50 holes per linear inch (50 mesh).

40/70 frac sand: Sand that passes through a sieve with 40 holes per linear inch (40 mesh) and is retained by a sieve with 70 holes per linear inch (70 mesh).

100 mesh frac sand: Sand that passes through a sieve with 100 holes per linear inch (100 mesh).

Acid solubility: A measure of how easily a substance dissolves into a low pH liquid solvent. Generally, the lower the acid solubility of a proppant, the more likely it is to retain its integrity when subjected to a low pH environment, which is often encountered in hydraulic fracturing of high-sulfur crude oil and natural gas deposits.

Barrel: An amount equal to 42 gallons.

Biodiesel: A domestic, renewable fuel for diesel engines derived from natural oils, and which is comprised of mono-alkyl esters of long chain fatty acids derived from vegetable oils or animal fats, designated B-100 and meeting the requirements of ASTM D 6751, “Standard Specification for Biodiesel Fuel (B-100) Blend Stock for Distillate Fuels.”

Ceramics: Artificially manufactured proppants of consistent size and sphere shape that offers a high crush strength.

Crush strength: Ability to withstand high pressures. Crush strength is measured according to the pounds per square inch of pressure that can be withstood before the proppant breaks down into finer granules.

Conductivity: A measure of how well a substance travels in a liquid medium. Generally, the smoother the surface of a proppant, the further it can travel when carried in a fracking solution to penetrate fissures in the source rock.

Dry plant: An industrial site where slurried sand product is fed through a dryer and screening system to be dried and screened in varying size gradations. The finished product that emerges from the dry plant is then stored in silos or stockpiles before being transported to customers or is immediately loaded onto a conveyance for transportation.

Frac sand: 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.

Hydraulic fracturing: The process of pumping fluids, mixed with granular proppants, into a geological formation at pressures sufficient to create fractures in the hydrocarbon-bearing rock.

Hydrotreater : A processing unit that removes sulfur and other impurities from raw or refined hydrocarbons through a catalyst or other means that combines the impurities with hydrogen. The resulting byproducts are then removed from the hydrocarbon stream, through a combination of temperature and pressure, and recycled.

ISO: International Organization for Standardization.

mcf: One thousand cubic feet of natural gas.

Mesh size: Measurement of the size of a grain of sand indicating it will pass through a sieve of a certain size.

Northern White sand: A monocrystalline sand with greater sphericity, roundness and low acid solubility, enabling higher crush strengths and conductivity, which is found primarily in Wisconsin's Jordan, Mt. Simon, St. Peter and Wonewoc formations.

Overburden: Layers of soil, clay and other waste covering a mineral deposit.

ppm: Parts per million.

Proppant: A sized particle mixed with fracturing fluid to hold fractures open after a hydraulic fracturing treatment.

Reserves: Natural resources, including sand, that can be economically extracted or produced at the time of determination based on relevant legal, economic and technical considerations.

Resin-coated sand: Raw sand that is coated with a flexible resin that increases the sand's crush strength and prevents crushed sand from dispersing throughout the fracture.

Roundness: A measure of how round the curvatures of an object are. The opposite of round is angular. It is possible for an object to be round but not spherical (e.g., an egg-shaped particle is round, but not spherical). When used to describe proppant, roundness

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is a reference to having a curved shape which promotes hydrocarbon flow, as the curvature creates a space through which the hydrocarbons can flow.

Sphericity: A measure of how well an object is formed in a shape where all points are equidistant from the center. The more spherical a proppant, the more highly conductive it is because it creates larger gaps that promote maximum hydrocarbon flow.

Shale Play: A geological formation that contains petroleum and/or natural gas in nonporous rock that requires special drilling and completion techniques.

Transmix: The liquid interface, or fuel mixture, that forms in refined product pipelines between batches of different fuel types.

Turbidity: A measure of the level of contaminants, such as silt and clay, in a sample.

Unit train: A train in which all of its cars are shipped from the same origin to the same destination, without being split up or stored en route.

Wet plant: An industrial site where quarried sand is fed through a stone breaking machine, crusher system and then slurried into the plant. The sand ore is then scrubbed and hydrosized by log washers or rotary scrubbers to remove the deleterious materials from the ore, and then separated using a vibrating screen and waterway system to generate separate 100 mesh and +70 mesh stockpiles, providing a uniform feedstock for the dryer. The ultra-fine materials are typically sent to a mechanical thickener, and eventually to settling ponds.

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PART I

ITEM 1. BUSINESS

Emerge Energy Services LP (“Emerge”) is a Delaware limited partnership that completed its initial public offering (“IPO”) on May 14, 2013, to become a publicly traded partnership. The combined entities of Superior Silica Sands LLC (“SSS”), a Texas limited liability company, and Allied Energy Company LLC (“AEC”), an Alabama limited liability company, represent the predecessor for accounting purposes (the “Predecessor”) of Emerge.

Immediately prior to the closing of the IPO, Insight Equity Management Company LLC and its affiliated investment funds and its controlling equity owners, Ted W. Beneski and Victor L. Vescovo (collectively “Insight Equity”) conveyed all of the interests in SSS and AEC to the Partnership as a capital contribution, and the Partnership conveyed its interests in SSS and AEC to the Partnership's subsidiary Emerge Energy Services Operating LLC (“Emerge Operating”), a Delaware limited liability company. In addition, the Partnership purchased Direct Fuels LLC (“Direct Fuels”), a Delaware limited liability company, through a combination of cash, issuance of common units, and assumption of debt, and the Partnership conveyed all of the interest in Direct Fuels to Emerge Operating. Therefore, the historical financial statements contained in this Form 10-K reflect the combined assets, liabilities and operations of the Partnership, SSS and AEC for periods ending before May 14, 2013 and the assets, liabilities and operations of the Partnership and all of its subsidiaries for periods beginning on or after May 14, 2013.

On August 31, 2016, Emerge completed the sale of its Fuel business pursuant to an Amended and Restated Purchase and Sale Agreement, dated August 31, 2016 (the “Fuel Business Purchase Agreement”), with Susser Petroleum Operating Company LLC and Sunoco LP (together, “Sunoco”). Sunoco paid Emerge a purchase price of $167.7 million in cash (subject to certain working capital and other adjustments in accordance with the terms of the Fuel Business Purchase Agreement), of which $14.25 million was placed into several escrow accounts to satisfy potential claims from Sunoco for indemnification under the Restated Purchase Agreement. Any escrowed funds remaining after certain periods of time set forth in the Restated Purchase Agreement will be released to Emerge, provided that no unsatisfied indemnity claims exist at such time. See Note 3 to our Condensed Consolidated Financial Statements for further discussion.

References to the “Partnership,” “we,” “our” or “us” when used for dates or periods ended prior to the IPO, refer collectively to the Predecessor. References to the “Partnership,” “we,” “our” or “us” when used for dates or periods ended on or after the IPO, refer collectively to Emerge and all of its subsidiaries.

Overview

We are a publicly-traded limited partnership formed in 2012 by management and affiliates of Insight Equity to own, operate, acquire, and develop a diversified portfolio of energy service assets. We are engaged in the business of mining, processing, and distributing silica sand, a key input for the hydraulic fracturing of oil and gas wells. We conduct our operations through our subsidiary SSS, and we believe our SSS brand has name recognition and enjoys a positive reputation with our customers.

On April 12, 2017, we closed the transaction to acquire substantially all of the assets of Materials Holding Company, Inc., Osburn Materials, Inc., Osburn Sand Co. and South Lehr, Inc. (San Antonio operations) for $20 million. The transaction was funded with a $40 million term loan, and the remaining proceeds (after transaction fees and expenses) were used to reduce outstanding borrowings under the revolving credit facility. This site is located 25 miles south of San Antonio, Texas and previously produced and sold construction, foundry and sports sands, but did not serve the energy markets. We upgraded the existing operations for conversion into frac sand production and commenced frac sand production in July 2017.

Our principal offices are located at 5600 Clearfork Main Street, Suite 400, Fort Worth, Texas 76109. Our telephone number is (817) 618-4020 and our website address is www.emergelp.com.

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Business Strategies

The primary components of our business strategy are:

•

Capitalize on the current market recovery. After two years of a prolonged energy market downturn, the North American oil and gas market exhibited a strong recovery in 2017 as energy prices rebounded significantly, prompting upstream companies to increase spending for drilling and completion activity. Frac sand market demand rebounded dramatically in 2017 to approximately 77 million tons compared to 39 million tons in 2016, and our frac sand sales volume grew from approximately 2 million tons in 2016 to over 5 million tons in 2017. With oil prices currently around $60 per barrel compared to below $30 per barrel for periods during the downturn, energy companies are expecting 2018 to be another year of sustained high investment. Additionally, the amount of proppant pumped downhole per horizontal well continues to increase at a high rate over the last several years, as the average proppant used per well in 2017 was nearly four times the amount used 2012. Oil and gas producers are continuing to realize improved hydrocarbon production and greater financial returns with the adoption of higher frac sand loadings per well, and we expect this trend to continue in 2018 based on published industry research and discussions with customers.

•

Expansion of Sand Resources. We are continually focused on growing our resource base and responding to the changing needs of the market and our customers. Over the past few years, the adoption of in-basin sand by oil and gas companies has increased. Although in-basin sand is typically lower quality than northern white sand, some oil and gas companies have determined that in-basin sand has adequate physical properties for a portion of their well designs, and the delivered cost advantages of in-basin sand can economically justify its usage. This trend has caused us to become a more diversified supplier of high quality northern white sand and in-basin sand. On April 12, 2017, we acquired our San Antonio operations for $20 million. This site is located 25 miles south of San Antonio, Texas and is within 40-75 miles of the drilling and completion activity in the Eagle Ford basin, which is currently the second most active shale play in the United States. This facility previously produced and sold construction, foundry and sports sands, but did not serve the energy markets. We upgraded the existing operations for conversion into frac sand production and commenced frac sand production in July 2017. As part of our in-basin expansion strategy, we began construction of a new wet and dry plant on the San Antonio site in October 2017. These additional plants are targeted to be operational by the second quarter of 2018. Our San Antonio reserves contain American Petroleum Institute (“API”) specification, strategic reserves that bolster our presence with in-basin local sands and balance our portfolio of northern white to local sands.

•

Focus on profitability and improving financial condition. We are applying financial discipline to all aspects of our business, with the primary goals of maximizing profits, controlling costs, prudently deploying capital for growth projects, and generating positive cash flow. We are constantly focused on lowering our production costs by efficiently operating our mines and dry plants, investing in operational projects that offer high returns, minimizing waste, and working closely with third-party contractors and vendors. Even when our operations are running at near full capacity as is the case in the current market environment, we continually seek to find the lowest cost combinations of sand source, production location, and transportation providers wherever possible. Furthermore, we routinely negotiate price concessions and purchase commitment amendments from our major vendors, such as railcar lessors, rail transportation providers, mine operators, transload facility operations, and professional service providers.

•

Build long-term customer relationships and execute on customer contracts. We seek to develop long-term customer relationships by providing a secure source of sand supply for our customers with a high level of service. We are constantly working to secure or renew long-term take-or-pay, fixed-volume, and efforts-based contracts with existing and new customers in order to cover the majority of our production capacity. In 2017, total sales to customers under long-term contracts, including efforts-based, fixed-volume, and take-or-pay arrangements, accounted for 52% of our sand sales volumes. As of December 31, 2017 , we had 5.8 million tons under long-term contract, primarily efforts-based arrangements, with a weighted average remaining of 3.5 years.

•

Introduce new products serving our core end users. We intend to increase our presence and market share in frac sand end markets that we believe are poised for growth. In September 2015, we introduced a unique, technically advanced proppant to the oil and gas industry and began selling the product in 2016. This dustless proppant, brand named SandGuard™, improves the handling, in-basin management, and job-site implementation of the hydraulic fracturing of oil and gas wells. Silica sands can potentially release dust particles into the air that are harmful to personnel when exposed in large quantities, so mechanical dust collection systems act to remove silica dust from the workplace. In March 2016, Occupational Health and Safety Administration (“OSHA”) published a final rule establishing a more stringent permissible limit for exposure to respirable crystalline silica and other provisions to protect employees, such as requirements for exposure assessment, methods for controlling exposure, respiratory protection, medical surveillance, hazard communication, and recordkeeping. This final rule became effective in June 2016, with compliance required by September 2017 for the construction industry and June 2018 for general industry and maritime. For operations in the oil and gas industry, compliance is required by June 2018, except for engineering controls, which have a compliance date of June

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2021. On December 22, 2017, the United States Court of Appeals for the District of Columbia Circuit upheld the OSHA rule protecting workers from exposure to silica dust. We believe that the new OSHA regulations could have a positive impact on demand for our SandGuard™ dustless product, as it eliminates the need for expensive dust collection systems at the wellsite or at a transload terminal. With a SandGuard™ treatment facility in Barron County, Wisconsin, we have the ability to enhance the already strong qualities of its northern white silica sand with the protective coating to help create a safer work environment for our customers’ employees.

In November 2015, we acquired 11 patents and other intellectual property assets from AquaSmart Enterprises LLC for their Self-Suspending Sand technology. The product brand is marketed as SandMaxX™. At our Barron dry plant, we have a pilot production circuit capable of producing in excess of 175,000 tons per year of SandMaxX™ product. This pilot production circuit uses proprietary and patented technology to coat all grades of standard frac sand. Although it remains subject to ongoing field testing and data validation, this new technology offers the potential to increase production in oil and gas wells in addition to improving pump time and reducing other upfront costs. Early results are proving that the technology is effective downhole, but the customer adoption rate has been slower than initially anticipated. We are still actively marketing the product and remain encouraged by the continued inquiries from existing and new customers. Our plans for constructing a commercial scale coating plant depend upon the successful completion of the field trial testing and achieving market acceptance of the product.


•	Distributions. While the Second Amended and Restated Revolving Credit Agreement and the Second Lien Note Purchase Agreement prohibit distributions in 2018, the board of directors of our general partner remains committed to resuming distributions as our financial condition allows.

Competitive Strengths

We believe that we are well positioned to successfully execute our business strategies because of the following competitive strengths:

•

High quality, strategically located assets. We currently operate several scalable frac sand production facilities in and around Barron County, Wisconsin, Kosse, Texas, and San Antonio, Texas. Our facilities in Wisconsin are supported by 70.7 million tons of proven recoverable sand reserves; our facility in Kosse, Texas is supported by 26.8 million tons of proven recoverable sand reserves; and our facility in San Antonio, Texas is supported by 47.6 million tons of proven recoverable frac sand reserves and 18.6 million tons of probable frac sand reserves. We believe that our Wisconsin and Texas reserves provide us access to a balanced amount of coarse sand (16/30, 20/40, and 30/50 mesh sands) and fine sand (40/70 and 100 mesh) compared to other frac sand producers. Our sample boring data and production data indicate that our Wisconsin reserves contain deposits of nearly 35% 40 mesh or coarser substrate, with our Barron reserves being comprised of more than 60% 50 mesh or coarser substrate. Our mine deposits in Wisconsin can be targeted to extract finer grades when the market dictates such demand, as is the current trend. Also, our Kosse, TX and San Antonio, TX operations primarily consist of fine sand product, which affords us significant flexibility of serving our customers with their desired product type. With the recent shift of some customers electing to use lower cost, in-basin sands, we have a diversified mix of product types to meet any needs of our customer base. Our Texas operations provide us in-basin local sands to satisfy customers who prefer such sand for economic reasons, while our three dry plants and five mines in Wisconsin provide high-quality northern white sand for those customers favoring quality over cost.

•

Logistics. The logistics capabilities of our Wisconsin facilities enable us to serve the major United States and Canadian oil and natural gas producing basins, as well as provide us with economical access to Mexico and South America. Our New Auburn facility is connected to a rail line owned by Union Pacific (“UP”), and our Barron facility is connected to the Canadian National (“CN”) rail line. Our Wisconsin plants are also located in close proximity to the Burlington Northern Santa Fe Railway (“BNSF”) rail line. Additionally, our San Antonio facility is located on the UP mainline. Although we expect to sell all of the San Antonio plant’s output in the Eagle Ford basin, the rail access affords us significant flexibility if we chose to ship sand to other basins. Between our two Wisconsin rail yards and our San Antonio site, we have storage space for 1,080 railcars. Our Barron and New Auburn dry plant facilities can accommodate unit trains. As of December 31, 2017 , we had a total of 5,199 railcars in our fleet, including 76 dedicated customer cars and 5,123 railcars under lease with a weighted average remaining term of 4.3 years. As of December 31, 2017 , we had 14 transload facilities in North America, each of which is positioned to serve a number of our target markets.


•	Competitive operating cost structure. We believe that our operations are characterized by an overall cost structure which allows us to capture attractive margins in the industries in which we operate. Our competitive cost structure is a result of the following key attributes:


•	close proximity of our silica sand reserves to our processing plants, which reduces operating costs;


•	close proximity of our in-basin sand operations (Kosse and San Antonio, TX) to oil and gas producing regions;

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•	expertise in designing, building, maintaining and operating advanced frac sand processing, storage and loading facilities;


•	a large proportion of the costs we incur in our production of sand are only incurred when we produce saleable frac sand;


•	open dialogue with key vendors, allowing for cost reductions;


•	proximity to major sand and logistics infrastructure, minimizing transportation and fuel costs and headcount needs;


•	competitive mineral royalty expenses;


•	enclosed dry plant operations which allow full run rates during winter months, thereby increasing plant utilization; and


•	a diversified and growing customer base spread across nearly every major shale play in North America.

•

Strong reputation with our customers, suppliers and other constituencies. Our management and operating teams have developed longstanding relationships with our customers, suppliers, and other constituencies. Based on our track record of dependability, timely delivery and high-quality products that consistently meet customer specifications, we believe that we are well positioned to secure additional contracted commitments in the future, and that our product mix and customer service will continue to benefit our reputation within the frac sand industry.

•

Experienced management team with industry specific operating and technical expertise. Our senior management team has extensive industry experience in managing and operating industrial mineral production facilities. They have managed numerous frac sand mining and processing plants, successfully led acquisitions in the industry and developed multiple greenfield industrial mineral processing facilities. We believe that our customers value our commitment to customer service, our reliable delivery, and our focus on high-quality product.

Our Business

We mine, process and distribute high quality silica sand, a key input for the hydraulic fracturing of oil and gas wells. Our Wisconsin facilities consist of three dry plants located in Arland, Barron and New Auburn, Wisconsin with a total permitted capacity of 6.3 million finished tons per year, and five wet plants and mine complexes that supply the dry plants with northern white silica sand, which we believe is the highest quality raw frac sand available. We also have a fourth dry plant in Kosse, Texas, with a capacity of 600,000 tons per year that is supplied by a separate mine and wet plant that processes local Texas sand. In April 2017, we purchased sand reserves and a wet plant in San Antonio that supplies the dry plant in San Antonio with local Texas sand. As of December 31, 2017 , we also had 14 transload facilities located throughout North America in the key basins where we deliver our sand, as well as a fleet of 5,199 railcars.

Our business experienced rapid growth from 2011 to 2014 due to technological advances in horizontal drilling and the hydraulic fracturing process that have made the extraction of large volumes of oil and natural gas from domestic unconventional hydrocarbon formations economically feasible. Demand for frac sand decreased during 2015 and 2016 as a result of the industry downturn. However, commodity prices stabilized in the middle of 2016, leading to an improvement in drilling activity during the third quarter of 2016 and into 2017. Market conditions improved significantly in 2017, and based on industry outlooks from third-party research firms and customers, we expect conditions to continue to improve in 2018. We believe that the premium geologic characteristics of our Wisconsin sand reserves, the strategic location of our sand mines, our location on multiple Class 1 rail lines, our extensive transload and logistics network, the industry experience of our senior management team, and the reputation that SSS has with our customers position us as a highly attractive source of frac sand to the oil and natural gas industry.

The production of our sand consists of three basic processes: mining, wet plant operations, and dry plant operations. All mining activities take place in an open pit environment, whereby we remove the topsoil, which is set aside, and then remove other non-economic minerals, or “overburden,” to expose the sand deposits. We then “bump” the sand using explosives on the mine face, which causes the sand to fall into the pit, where it is then carried by truck to the wet plant operations. We also utilize a process called hydraulic mining whereby we use high pressure water cannons to dislodge the sandstone, and transport the sand and water mixture via pipeline to the wet plant. Where the geology is suitable, this technique minimizes the use of heavy excavation machinery, thereby lowering operating costs. Once we have mined out a portion of the reserves, we then either return the land to its previous contours or to a more usable contour. We also replace the topsoil in Wisconsin. At our wet plants, the mined sand goes through a series of processes designed to separate the sand from unusable materials. The resulting wet sand is then conveyed to a wet sand stockpile where most of the water is allowed to drain into our on-site recycling facility, while the remaining fine grains and other materials, if any, are separated through a series of settlement ponds. We reuse all of the water that does not evaporate in our wet process. Wet sand from our stockpile is then conveyed or trucked to our dry plants where the sand is dried, screened into specific

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mesh categories, and stored in silos. From the silos, we load sand directly into railcars or trucks, which we then ship to one of our transload facilities or directly to one of our customers.

Our frac sand facilities are located in Barron County and Chippewa County, Wisconsin, Kosse, Texas and San Antonio, Texas. Based on the reports of third-party independent engineering firms, we have 145.1 million tons of proven recoverable reserves. We are currently capable of producing up to 9.6 million tons and 7.2 million tons of wet and dry sand per year, respectively, from our current facilities. We believe that the coarseness, conductivity, sphericity, acid-solubility, and crush-resistant properties of our Wisconsin reserves and our facilities' connectivity to rail and other transportation infrastructure afford us an advantage over our competitors and make us one of a select group of sand producers capable of delivering high volumes of frac sand that is optimal for oil and natural gas production to all major unconventional resource basins currently producing throughout North America and abroad.

Our Wisconsin sand reserves give us access to a range of high-quality sand that meets or exceeds all API specifications and includes a mix between concentrations of coarse grades (16/30, 20/40 and 30/50 mesh sands) and finer grades (40/70 and 100 mesh). While our Wisconsin reserves provide us access to a high amount of coarse sand compared to other northern white deposits located in Wisconsin's Jordan and Wonewoc formations, we have the ability to target certain locations in our deposits to obtain finer sands. Our sample boring data and our historical production data have indicated that our Wisconsin reserves contain deposits of nearly 35% 40 mesh or coarser substrate, with our FLS, Church Road, LP Mine and Thompson Hills reserves being comprised of more than 60% 50 mesh or coarser substrate. We are also one of a select number of mine operators that can offer commercial amounts of 16/30 mesh sand, the coarsest grade of widely-used frac sand on the market. Our Wisconsin dry plants are fully enclosed, which means that we are capable of running year-round, regardless of the weather. Under normal market conditions, we operate our Wisconsin plants with work crews of four to six employees. These crews work 40-hour weeks, with shifts between eight and twelve hours, depending on the employee's function. Because raw sand cannot be wet-processed during extremely cold temperatures, we typically mine and wet-process frac sand eight months out of the year at our Wisconsin locations.

On April 12, 2017, we closed the transaction to acquire our San Antonio operations for $20 million. The San Antonio site is located approximately 25 miles south of San Antonio, Texas and previously produced and sold construction, foundry and sports sands, but did not serve the energy markets. We upgraded the existing operations for conversion into frac sand sales and commenced frac sand production in July 2017. Our mine, wet plant and dry plant in San Antonio, Texas operates year-round. We currently operate our facilities with crews of 10 to 12 employees who work twelve-hour shifts and average 46 hours a week. As part of our expansion strategy in San Antonio, we began construction of an additional plant on the site in October 2017. This plant is targeted to be operational by the second quarter of 2018. Our San Antonio reserves contain API-specification, strategic reserves (40/70 and100 mesh sands) that bolster our presence with in-basin local sands and balance our portfolio of northern white to local sands. With the close proximity of the plant to the Eagle Ford basin, we expect to sell the majority of the sand produced at the plant into this shale play, which is currently the second most active in the United States.

Our mine, wet plant, and dry plant in Kosse, Texas operates year-round. The reserves primarily consist of finer mesh grades, which strategically complement the coarser grades from our Wisconsin deposits. We operate our Kosse facilities with crews of four to six employees who work twelve-hour shifts and average 40 hours per week. This allows us to optimize facility utilization.

Each of our facilities undergoes regular maintenance to minimize unscheduled downtime and to ensure that the quality of our frac sand meets applicable ISO and API standards and our customers' specifications. In addition, we make capital investments in our facilities as required to support customer demand and our internal performance goals.

The following table provides information regarding our frac sand production facilities as of December 31, 2017 .



Wet Plant Location	Proven Recoverable Reserves (Millions of Tons) (1)	Lease Expiration Date (2)	Annual Plant Capacity (Thousands of Tons)	2017 Production (Thousands of Tons)
Auburn	16.4	March 2036	2,000	1,276
Thompson Hills	38.2	December 2037	1,600	1,394
FLS Mine	7.9	July 2037	1,400	1,496
Church Road	4.4	N/A	1,200	924
LP Mine	3.8	March 2038	1,200	1,163
San Antonio, TX (4)	47.6	N/A	600	77
Kosse, TX	26.8	N/A	1,600	321

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Dry Plant Location (1)	On-site Railcar Storage Capacity (3)	Annual Plant Capacity (Thousands of Tons)	2017 Production Volumes (Thousands of Tons)
Arland	N/A	2,500	1,800
Barron	650 cars	2,400	2,081
New Auburn	420 cars	1,400	1,272
San Antonio, TX	10	300	50
Kosse, TX	N/A	600	231


(1)	Reserves are estimated as of December 31, 2017 , by third-party independent engineering firms based on core drilling results and in accordance with the SEC’s definition of proven recoverable reserves and related rules for companies engaged in significant mining activities and represent marketable finished product.


(2)	We own the land and mineral rights at our Church Road, Kosse, and San Antonio mines.


(3)	We transload sand produced at Arland to rail loadouts at New Auburn, Barron, and a third location in Minnesota.


(4)	San Antonio facility also has 18.6 million tons of probable frac sand reserves.

Mineral Reserves

We believe that our strategically located mines and facilities provide us with a large, high-quality, and diversified mineral reserve base. The coarseness and high crush strength of the northern white frac sand that we mine in Wisconsin offers superior physical properties compared to in-basin, finer-mesh sand that we offer from our Kosse and San Antonio, TX locations. Certain customers prefer our higher quality sand mined in Wisconsin because it can enhance the recovery of hydrocarbons in certain geological formations, particularly higher stress and deeper wells. However, other customers prefer the lower quality sand mined at our Texas locations as this product has adequate physical characteristics for certain shallower well formations but offers a lower landed cost to the wellsite given the mines’ proximity to active drilling regions.

We categorize our reserves as proven or probable recoverable in accordance with SEC definitions and have further limited the definition to apply only to sand reserves that we believe could be extracted at an average cost that is economically feasible. According to such a definition, we estimate that we had a total of 145.1 million tons of proven recoverable mineral reserves as of December 31, 2017 . The quantity and nature of the mineral reserves at each of our properties are estimated first by third-party geologists and mining engineers and we internally track the depletion rate on an interim basis. Cooper Engineering Company, Inc. prepared estimates of our proven mineral reserves at our Wisconsin mine locations, while Westward Environmental, Inc. prepared estimates of our proven mineral reserves at our Kosse facility, each as of December 31, 2017 . Our San Antonio proven and probable reserve estimates were prepared by Westward Environmental, Inc. at the time of the acquisition in April 2017. Our external geologists and engineers update our reserve estimates annually, making necessary adjustments for operations at each location during the year and additions or surveying, drill core analysis and other tests to confirm the quantity and quality of the acquired reserves.

Our mineral reserve leases in Wisconsin with third-party landowners expire at various times between 2036 and 2038. We do not anticipate any issues in renewing these leases should we decide to do so. Consistent with industry practice, we conduct only limited investigations of title to the leased properties prior to leasing. Title to lands and reserves of the lessors or grantors and the boundaries of our leased properties are not completely verified until we prepare to mine those reserves.

Mines and Wet Plants

The deposits found in our open-pit Wisconsin-based mines are Cambrian quartz sandstone deposits that produce high-quality northern white frac sand and have a minimum silica content of 99%. Mining takes place in phases lasting from six months to one year in duration, after which the property is reclaimed in a manner that typically provides the landowners with additional cropland.

Our San Antonio deposits are Eocene-aged Carrizo sand formations which can be used in a variety of specialized sand applications including frac sand. Prior to our acquisition in April 2017, our San Antonio plant produced and sold construction, foundry and sports sands, but did not serve the energy markets. We upgraded the existing operations for conversion into frac sand production and commenced frac sand production in July 2017.

New Auburn

Our New Auburn wet plant can process up to 2 million tons of wet sand per year. It is located in Chippewa County, Wisconsin, 12 miles from our New Auburn dry plant, to which we have year-round trucking access. The mine site consists of 418 acres adjacent to our New Auburn wet plant. The site contains 16.4 million tons of proven recoverable sand reserves.

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We awarded Fred Weber, Inc. (“Weber”) a contract for the entirety of our Auburn mining operations and for a portion of our wet processing needs at that facility. Under this contract, Weber financed and built the wet plant at our Auburn facility. This contract expires in December 31, 2021. We agreed, under a take-or-pay arrangement, to purchase 500,000 tons of washed sand from Weber each year that the plant is in operation. During the term of the agreement Weber will own the wet plant along with the equipment and other temporary structures used for mining on the property. Subject to certain conditions, ownership of the plant and equipment will transfer from Weber to us at the expiration of the term.

Thompson Hills

Our Thompson Hills wet plant can process up to 1.6 million tons of wet sand per year. It is located 15 miles from our New Auburn dry plant and 26 miles from our Barron dry plant. The mine site is situated on 580 acres and consists of a series of seven leases in Barron County, Wisconsin. The site contains 38.2 million tons of proven recoverable sand reserves.

We completed construction of the mine and wet plant in September 2014. We incorporated two features into the wet plant that we believe provide the plant with higher quality sand within a more environmentally sound footprint. The first is that we wash our sand both before and after we run the wet sand through the hydrosizer. The resulting sand has low turbidity, which results in less fugitive dust both at our facilities and at the drilling site for our customers. The second is that we separate our fines and other unusable material without the use of settling ponds, which enables us to use less water in our wet plant. Hydraulic mining was implemented at this site during the third quarter of 2015, reducing our mining costs.

FLS mine

Our FLS wet plant can process up to 1.4 million tons of wet sand per year. It is located 12 miles from our Barron dry plant. The mine site is situated on 364 acres and consists of a series of five adjacent mineral deposits in Barron County, Wisconsin. The site contains 7.9 million tons of proven recoverable sand reserves.

Church Road

Our Church Road wet plant can process up to 1.2 million tons of wet sand per year. It is located less than one mile from our Arland dry plant. The mine site is situated on 130 acres. The site contains 4.4 million tons of proven recoverable sand reserves.

LP Mine

Our LP wet plant can process up to 1.2 million tons of wet sand per year. It is located 2 miles from our Arland dry plant. The mine site is situated on 145 acres. The site contains 3.8 million tons of proven recoverable sand reserves. Hydraulic mining was implemented at this site during the third quarter of 2015.

San Antonio

In April 2017, we completed the asset acquisition of our San Antonio site which is located 25 miles south of San Antonio, Texas. Our San Antonio mine is situated on 650 acres and previously produced and sold construction, foundry and sports sands, but did not serve the energy markets. We upgraded the existing operations for conversion into frac sand production and commenced frac sand production in July 2017. San Antonio has API-specification, strategic reserves that bolster our presence with in-basin local sands and balance our portfolio of northern white to local sands. As of December 31, 2017, our San Antonio deposit contained 47.6 million tons of proven recoverable reserves and 18.6 million tons of probable frac sand reserves. The wet plant currently has a capacity to produce 600,000 tons of wet sand per year. We are not obligated to make royalty payments in connection with our mining operations at this location. As part of our expansion strategy in San Antonio, we began construction of an additional frac sand plant on the site in October 2017. This additional plant is targeted to be operational by the second quarter of 2018.

Kosse

We own the mineral rights to a 225 acre mineral deposit located in Kosse, Texas, adjacent to our Kosse dry plant. The deposit has a minimum silica content of 99% and controlling attributes that include sand grain crush strength and size distribution. As of December 31, 2017 , the Kosse mineral deposit contained 26.8 million tons of proven recoverable reserves which we process into a high-quality, 100 mesh frac sand. The wet plant at our Kosse facility is capable of producing up to 1.6 million tons of wet sand per year. We are not obligated to make royalty payments in connection with our mining operations at this location. We use heavy equipment to mine sand from the open pit. We introduced hydraulic mining techniques to our Kosse mine in 2016.

Dry Plant Facilities

Arland

Our Arland dry plant is located in the township of Arland in Barron County, Wisconsin on 22 acres that we own. The facility is located on a county road, which gives us year-round trucking access, and is situated 11 miles from our Barron facility, and 37 miles from our New Auburn facility. Our Arland dry plant is an enclosed facility that has a rated production capacity of 8,800 tons per day year-round, regardless of weather conditions. Our current air permit allows us to produce up to 3.5 million tons per

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year of finished product. The facility has a 300 ton per hour natural gas fired rotary dryer as well as twelve high capacity gyratory mineral separators (“screeners”) that are capable of producing up to 2.5 million tons per year. Our finished product is transported via truck to one of our dry plant facilities with rail access or to a third-party rail loadout facility located in Minnesota.

For the year ended December 31, 2017 , our Arland facility produced 1.8 million tons of northern white frac sand.

Barron

Our Barron dry plant is located in the township of Clinton, Wisconsin in Barron County on 83 acres that we own. The facility is located on a US Highway, which gives us year-round trucking access, and is situated along a rail spur owned by the Canadian National (“CN”) railway that connects to the CN main line. Our Barron dry plant is an enclosed facility that has a rated production capacity of 8,800 tons per day year-round regardless of weather conditions, and has on-site railcar loading facilities. Our current air permit allows us to produce up to 2.4 million tons per year of finished product. The facility has a 300 ton per hour natural gas fired rotary dryer as well as twelve high capacity screeners. Our railyard at Barron consists of 18 spur tracks and is capable of storing up to 650 railcars.

Our location on the CN rail spur allows us to offer direct access to the rapidly growing oil and gas shale plays in northwestern Canada and the northeastern United States, including the Western Canadian Sedimentary Basin, the Marcellus Shale, and the Utica Shale plays. The CN also presents us with access to the southern United States as well as the port of New Orleans, which provides us access to emerging oil and gas markets in Latin America.

The Barron facility houses our technology-driven proppant (SandGuard™ and SandMaxX™) production circuits. In late 2015, we installed equipment that applies coating material for our SandGuard™ product. Our SandMaxX™ pilot plant upgrade is operational and will provide production in limited quantities until the technology is tested in the field. If the technology proves successful and widely demanded by our customers, we will evaluate a larger-scale upgrade to an existing facility.

For the year ended December 31, 2017 , our Barron facility produced 2.1 million tons of northern white sand.

New Auburn

Our New Auburn dry plant is located in Barron County, Wisconsin, 12 miles from our New Auburn mine. The facility is on 37 acres that we own in the village of New Auburn, Wisconsin along a short line that connects with the mainline of the UP railway. Our New Auburn dry plant is an enclosed facility that has a rated production capacity of 4,400 tons per day year-round regardless of weather conditions, and has on-site railcar loading facilities capable of loading railcars. Our current air permit allows us to produce up to 1.4 million tons per year of finished product. The facility has a 175 ton per hour natural gas fired fluid bed dryer as well as six screeners.

We have access to a segment of on-site rail track that is tied into a rail line owned by UP, and we use this rail space to stage and store empty or recently loaded customer railcars. Because of the cost efficiencies of shipping frac sand by rail, our location adjacent to a UP short line provides our customers with the ability to transport northern white frac sand from our New Auburn facility to major oil and natural gas basins currently producing in the United States and western Canada, including access to high-activity areas of oil production in Texas, Oklahoma, Colorado and the western United States.

For the year ended December 31, 2017 , our New Auburn facility produced 1.3 million tons of northern white sand.

San Antonio.

In April 2017, we completed the asset acquisition of our San Antonio site which is located 25 miles south of San Antonio, Texas. The San Antonio dry plant previously produced and sold construction, foundry and sports sands, but did not serve the energy markets. We upgraded the existing operations for conversion into frac sand production and commenced frac sand production in July 2017. This plant has a production capacity of 300,000 tons per year. As part of our expansion strategy, we began construction of an additional plant on the site in October 2017. This additional plant is targeted to be operational by the second quarter of 2018 and will be capable of producing 4 million tons per year of finished dry sand. This facility has direct trucking to a four lane US highway to serve the Eagle Ford basin. With the close proximity of the plant to the Eagle Ford basin, we expect to sell the majority of the sand produced at the plant into this shale play, which is currently the second most active in the United States. We have access to a segment of on-site rail track that is tied into a rail line owned by UP mainline and access to BNSF mainline is 15 miles away. We may utilize these transportation options if market conditions change and we begin serving other basins from this plant. We will continue to sell sand to non-energy markets including construction, foundry and sports sands.

From July 2017 through December 31, 2017 , our San Antonio facility produced 50,000 tons of frac sand.

Kosse

Our Kosse dry plant is located adjacent to our Kosse mine and wet plant on land we own in Kosse, Texas. The facility has a rated production capacity of 1,650 tons per day year-round. The dry plant utilizes a 200 ton per hour natural gas fired rotary dryer that is capable of producing up to 600,000 tons per year of dry native Texas frac sand, and has an air permit that allows us to produce

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up to 1.2 million tons per year of finished product. The plant produces 100-mesh native Texas sand and is capable of producing a higher-cut 40/70 frac sand. We also sell sand to non-energy end users, including industrial applications, and sports sand for golf courses, stadiums and other sports-related venues. The Kosse facility has three on-site 1,000-ton storage silos designed for loading trucks for delivery to local and regional markets.

For the year ended December 31, 2017 , our Kosse facility produced 231,000 tons of frac sand.

Transportation Logistics and Infrastructure

We sell our sand both free-on-board (“FOB”) at our plants as well as at transload facilities that are closer to the wellhead. As the frac sand market has evolved, the point of sale between producers and purchasers of frac sand continues to move away from the FOB plant model and closer to the wellhead. For the year ended December 31, 2017, we sold 56% of our sand FOB plant and 44% FOB transload. At our Texas plants, orders are picked up by truck because most orders are transported 200 miles or less from our plant sites. Because nearly all product from our Wisconsin plants is transported in excess of 200 miles and transportation costs typically represent more than 50% of our customers' overall cost for delivered northern white sand, the majority of our Wisconsin shipments are transported by rail to a transload and storage location in close proximity to the customer's intended end use destination.

While many of our customers continue to purchase FOB plant, we offer our customers a total supply chain solution pursuant to which we manage every aspect of the supply chain from mining and manufacturing to delivery within close proximity to the wellhead. Currently, we have built a fleet of company-leased and customer-committed railcars, assembled a network of leased transload and terminal storage sites located near major shale plays, and designed a supply chain management system, all of which allow us to flexibly and efficiently coordinate rail, truck, and storage assets with customer order information.

Transload Facilities

Due to limited storage capacity at or near the wellhead, our customers generally find it impractical to store frac sand in large quantities immediately near their job sites. We can service manifest rail deliveries or unit train shipments and minimize product fulfillment lead times through the simultaneous handling of multiple customers' railcars. In order to continue to service the customer closer to the wellhead, we have assembled a network of transload facilities within a number of the major basins that we serve. Below is a summary of the transload sites that we operate out of as of December 31, 2017 .



Transload Location by Basin	Transload Sites as of December 31, 2017	Transload Sites Capable of Receiving Unit Trains	2017 Volume Sold (Thousands of Tons)
Bakken Shale	1	1	309
Barnett Shale	1	—	2
Eagle Ford Shale	1	1	514
Haynesville Shale	1	1	65
Marcellus / Utica Shales	2	1	154
Mid-Continent Basin	1	1	128
Permian Basin	3	2	540
Western Canadian Sedimentary Basin	3	—	358
Export to South America	1	—	14
Total tons sold through transloads active at December 31, 2017	14	7	2,084
Tons sold through transloads not active at December 31, 2017			364
Tons sold through transloads in 2017			2,448

As of December 31, 2017 , we had a total of 5,199 railcars in our fleet, including 76 railcars that are owned or leased by our customers but dedicated to us, and 5,123 railcars that we lease with a weighted average remaining term of 4.3 years.

Permits

In order to conduct our sand operations, we are required to obtain permits from various local and state governmental agencies. The various permits we must obtain address such issues as mining, construction, air quality, water discharge, noise, dust, and reclamation. Prior to receiving these permits, we must comply with the regulatory requirements imposed by the issuing governmental authority. In some cases, we also must have certain plans pre-approved, such as site reclamation plans, prior to obtaining the required permits. A decision by a governmental agency 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 affect on our ability to continue operations at the affected facility. Expansion of our existing operations also is predicated upon securing the necessary environmental

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and other permits and approvals. We have obtained all permits required for the operation of our existing facilities. We will also obtain permits necessary to process and distribute any new product, as might be required.

Intellectual Property

Our intellectual property consists primarily of patents, trade secrets, know-how and products such as “SandMaxX™” and “SandGuard™.” We hold 12 U.S. granted patents that are still in force, the majority of which have an expiration date after 2027. Typically, we utilize trade secrets to protect the formulations and processes we use to manufacture our products and to safeguard our proprietary formulations and methods. We believe we can effectively protect our trade secrets indefinitely through the use of confidentiality agreements and other security measures.

Customers

We sell substantially all of our sand to customers in the oil and gas proppants market. Our customers include major oilfield services companies as well as exploration and production companies that are engaged in hydraulic fracturing. Sales to the oil and gas proppants market comprised of 99% of our total sales in 2017. For the year ended December 31, 2017 , our top two customers, Liberty Oilfield Services and EP Energy Corporation, collectively accounted for 35% of our total revenues from continuing operations. For the year ended December 31, 2016 , our top two customers, EP Energy Corporation and Universal Pressure Pumping, Inc., collectively accounted for 51% , of our total revenues from continuing operations. Non-frac sand sales accounted for 1% of our total sales in 2017. Sales of non-frac sand consists of customers in the sports sands, construction, and foundry industries.

In 2017 , total sales to customers under long-term contracts, including take-or-pay, fixed-volume, and efforts-based contracts, accounted for 52% of our total sales. As of December 31, 2017 , we had 5.8 million tons under long-term contract with a weighted average remaining term of 3.5 years.

Suppliers and Service Providers

We depend on our suppliers at multiple Class 1 rail lines to transport frac sand produced at our Wisconsin plants to our customers, whose operations are located across several oil and gas-producing regions in North America. Given high trucking costs for shipping frac sand beyond a 200 mile radius, rail is the most competitive mode of transportation for our Wisconsin operations. We work directly with the UP, CN, and BNSF railroads on an ongoing basis to determine the best origin and destination pairings for our customers. During periods of surging market demand, as is the case in the current market environment, we can experience periods of temporary service disruptions from our rail partners. We have strong relationships with these rail providers, and we work closely with the railroads to minimize service disruptions when they occur.

Competition

The frac sand market is a highly competitive market that is comprised of a small number of large, national producers, which we also refer to as “Tier 1” producers, and a larger number of small, regional, or local producers. Competition in the frac sand industry has increased recently due to favorable pricing and demand trends, and we expect competition to increase in the future as new entrants are beginning operations in 2018 with local, in-basin sand mines. Suppliers compete based on price, consistency, quality of product, site location, distribution capability, customer service, reliability of supply, breadth of product offering and technical support.

Based on management's internal estimates, we believe we were one of the five largest producers of frac sand in 2017 by production capacity and sales volumes, together with U.S. Silica Holdings, Inc., Hi-Crush Proppants LLC, Unimin Corporation, and FMSA Holdings, Inc. In recent years there has also been an increase in the number of small producers servicing the frac sand market due to increased demand for hydraulic fracturing services and related proppant supplies. We believe, however, that the relative inexperience of many management teams operating in the frac sand industry coupled with the costs, length of time and operational challenges associated with identifying attractive frac sand reserves, obtaining necessary permits and regulatory approvals and constructing a sand processing facility will prevent these smaller competitors from prospering in the long run. Further, the financial commitments and expertise required to develop a national logistics network is a barrier to entry.

Seasonality

At our Wisconsin operations, it is challenging to process raw sand during prolonged sub-zero temperatures; therefore, frac sand is typically water-washed only eight months of the year at our Wisconsin operations. This results in a seasonal build-up of inventory as we excavate excess sand to build a stockpile to feed the dry plants during the winter months, causing the average inventory balances to increase from a few weeks in early spring to more than 100 days in early winter. These seasonal variations in inventory balance affect our cash flow. We may also sell frac sand for use in oil and gas basins where severe winter weather conditions may curtail drilling activities, and, as a result, our sales volumes to those areas may be adversely affected. For example, we could experience a decline in both volumes sold and income for the second quarter relative to the first quarter each year due to seasonality of frac sand sales into western Canada because sales volumes are generally lower during April and May due to limited drilling activity resulting from that region's annual thaw.

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Insurance

We believe that our insurance coverage is customary for the industries in which we operate and adequate for our business. We periodically review insurance plans to address most, but not all, of the risks against 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, 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 environmental laws and regulations may expose us to significant costs and liabilities and cause us to incur significant capital expenditures in our operations. We are often obligated to obtain permits or approvals in our operations from various federal, state and local authorities. These permits and approvals can be denied or delayed, which may cause us to lose potential and current customers, interrupt our operations and limit our growth and revenue. Moreover, 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.

We do not believe that compliance 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. However, we cannot assure 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 that relate to our operations.

Air emissions. Our operations are subject to the Clean Air Act, as amended (the “CAA”), and comparable state and local laws that restrict the emission of air pollutants from certain sources and also impose various monitoring and reporting obligations. Compliance with these laws and regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air emissions permit requirements or utilize specific equipment or technologies to control emissions. 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 such as, by way of example, the capture of increased amounts of fine sands matter emitted from produced sands. In addition, air permits are required for our frac sand mining operations that result in the emission of regulated air contaminants. These permits incorporate the various control technology requirements that apply to our operations and are subject to extensive review and periodic renewal. Any future changes to existing requirements, non-compliance, or failure to maintain necessary permits or other authorizations could require us to incur substantial costs or suspend or terminate our operations.

On August 16, 2012, the EPA published final rules that establish new air emission controls and practices for oil and natural gas production wells, including wells that are the subject of hydraulic fracturing operations and natural gas processing operations. The EPA later updated the storage tank standards on August 5, 2013, to phase in emission controls more gradually. In May 2016, the EPA finalized additional regulations to control emissions of methane and volatile organic compounds from the oil and natural gas sector. In April 2017, the EPA announced that it would review such regulations, and in December 2017, the EPA issued a final rule that would stay its methane rule for two years. Compliance with these rules could result in significant costs to our customers, which may have an indirect adverse impact on our business.

There can be no assurance that future requirements compelling the installation of more sophisticated emission control equipment would not have a material adverse impact on our business, financial condition, or results of operations.

Climate change. In recent years, the U.S. Congress has considered legislation to reduce emissions of GHGs. It presently appears unlikely that comprehensive climate change 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, almost half of the states have begun to address GHG emissions, primarily through the planned 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 CAA. For example, the EPA has adopted rules requiring the reporting of GHG emissions in the United States for emissions from specified large GHG emission sources. The EPA also has adopted rules establishing construction and operating permit requirements for certain large stationary sources of GHG emissions that are already potential major sources of criteria pollutants.

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Although it is not currently possible to predict how any such proposed or future GHG legislation or regulation by Congress, the EPA, the states or multi-state regions will impact our business, any legislation or regulation of GHG emissions that may be imposed in areas in which we conduct business could result in increased compliance costs or additional operating restrictions or reduced demand for our services, and could have a material adverse effect on our business, financial condition and results of operations.

Further, in December 2015, over 190 countries, including the United States, reached an agreement to reduce global GHG emissions. The agreement entered into force in November 2016 after more than 70 countries, including the United States, ratified or otherwise consented to be bound by the agreement. In June 2017, President Trump stated that the United States would withdraw from the agreement, but may enter into a future international agreement related to GHGs on different terms. The 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 is uncertain and/or the terms on which the United States may reenter the agreement or a separately negotiated agreement are unclear at this time. To the extent the United States or any other country implement this agreement or impose other climate change regulations on the oil and gas industry, it could have an adverse direct or indirect effect on our business.

Water discharge. The Clean Water Act, as amended (the “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 regulated waters. 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. The CWA and regulations implemented thereunder also prohibit the discharge of dredge and fill material into regulated waters, including jurisdictional wetlands, unless authorized by an appropriately issued permit. The CWA also requires the development and implementation of spill prevention, control and countermeasures, including the construction and maintenance of containment berms and similar structures, if required, to help prevent the contamination of regulated waters in the event of a petroleum hydrocarbon tank spill, rupture or leak at such facilities. 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. 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.

Safe Drinking Water Act . Although we do not directly engage in hydraulic fracturing activities, our customers purchase our frac sand for use in their hydraulic fracturing operations. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into the formation to stimulate oil and natural gas production. Legislation to amend the Safe Drinking Water Act (the “SDWA”) to repeal the exemption for hydraulic fracturing from the definition of “underground injection” and require federal permitting and regulatory control of hydraulic fracturing, as well as legislative proposals to require disclosure of the chemical constituents of the fluids used in the fracturing process have been proposed in recent sessions of Congress. We cannot predict whether any such legislation will ever be enacted and, if so, what its provisions would be. Scrutiny of hydraulic fracturing activities continues in other ways, with the EPA having released a final report regarding the impacts of hydraulic fracturing on drinking water resources in 2016. The report concluded that certain activities associated with hydraulic fracturing may impact drinking water resources under certain circumstances. In addition, the U.S. Department of Energy released a series of recommendations for improving the safety of the process in 2011. Further, the EPA and the U.S. Department of the Interior (the “DOI”) have adopted new regulations for certain aspects of the process. For example, the EPA finalized effluent limitations for the treatment and discharge of wastewater resulting from hydraulic fracturing. The DOI adopted rules that require disclosure of chemicals used in hydraulic fracturing activities upon federal and Indian lands and also would strengthen standards for well-bore integrity and the management of fluids that return to the surface during and after fracturing operations on federal and Indian lands. However, in December 2017, the DOI rescinded its rule regulating hydraulic fracturing activities on federal and Indian lands. At the state level, some states, including Texas, have adopted, and other states are considering adopting, legal requirements that could impose more stringent permitting, public disclosure or well construction requirements on hydraulic fracturing activities. If additional levels of regulation and permits were required through the adoption of new laws and regulations at the federal or state level, that could lead to delays, increased operating costs and process prohibitions that could make it more difficult to complete natural oil and gas wells in shale formations, increasing 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 frac sand products. In addition, heightened political, regulatory and public scrutiny of hydraulic fracturing practices could potentially expose us or our customers to increased legal and regulatory proceedings, and any such proceedings could be time-consuming, costly or result in substantial legal liability or significant reputational harm. Any such developments could have a material adverse effect on our business, financial condition and results of operations, whether directly or indirectly. For example, 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 in the geographic areas we serve.

Solid waste. The Resource Conservation and Recovery Act, as amended (the “RCRA”), and comparable state laws control the generation, storage, treatment, transfer and disposal of hazardous and non-hazardous waste. The EPA and various state agencies have limited the approved methods of disposal for these types of wastes. In the course of our operations, we generate waste that may be regulated as non-hazardous wastes or even hazardous wastes, obligating us to comply with applicable RCRA standards relating to the management and disposal of such wastes.

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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. On November 21, 2013, the EPA issued a General Notice Letter and Information Request (“Notice”) under Section 104(e) of CERCLA to one of our former subsidiaries. The Notice provides that the subsidiary may have incurred liability with respect to the Reef Environmental site in Alabama, and requested certain information in accordance with Section 107(a) of CERCLA. At this time, no specific claim for cost recovery has been made by the EPA (or any other potentially responsible party) against the Partnership. There is uncertainty relating to our share of environmental remediation liability, if any, because our allocable share of wastewater is unknown and the total remediation cost is also unknown. Consequently, management is unable to estimate the possible loss or range of loss, if any. We have not recorded a loss contingency accrual in our financial statements. In the opinion of management, the outcome of such matters will not have a material adverse effect on our financial position, liquidity, or results of operations.

The soil and groundwater associated with and adjacent to our former Dallas-Fort Worth terminal property have been affected by prior releases of petroleum products or other contaminants. A past owner and operator of the terminal property, ConocoPhillips, has been working with TCEQ to address this contamination. We, ConocoPhillips and owners and operators of adjacent industrial properties undertaking unrelated remediation obtained a Municipal Setting Designation (“MSD”) from the City of Fort Worth, which is an ordinance prohibiting the use of groundwater as drinking water in the area of our former terminal property. Following the certification of this MSD by the TCEQ, ConocoPhillips obtained approval of a remedial action plan for the property, which now only requires recordation of a restrictive covenant to comply with the TCEQ requirements. In connection with the sale of this facility, we have agreed to hold our successor harmless from any claims arising from this contamination, none of which has been asserted to our knowledge. We do not believe this former facility is likely to present any material liability to us.

Endangered Species. The Endangered Species Act (“ESA”), restricts activities that may affect endangered or threatened species or their habitats. The designation of certain species has not caused us to incur material costs or become subject to operating restrictions or bans. However, the designation of previously unidentified endangered or threatened species could cause us to incur additional costs or become subject to operating restrictions or bans or limit future development activity in the affected areas. Moreover, as a result of a settlement approved by the U.S. District Court for the District of Columbia on September 9, 2011, the U.S. Fish and Wildlife Service is required to consider listing more than 250 species as endangered under the Endangered Species Act. Under the September 9, 2011, settlement, the U.S. Fish and Wildlife Service (“FWS”) is required to review and address the needs of more than 250 species on the candidate list before the completion of the agency's 2017 fiscal year. The FWS did not meet that deadline. The designation of previously unprotected species as threatened or endangered in areas where our exploration and production 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 customers' performance of operations, which could reduce demand for our services.

Mining and Workplace Safety. Our sand mining operations are subject to mining safety regulation. The U.S. Mine Safety and Health Administration (“MSHA”) is the primary regulatory organization governing the frac sand industry. Accordingly, MSHA regulates quarries, surface mines, underground mines and the industrial mineral processing facilities associated with 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 worker safety and health standards. MSHA works closely with the Industrial Minerals Association, a trade association in which we have a significant leadership role, in pursuing this mission. As part of MSHA's oversight, representatives perform at least two unannounced inspections annually for each aboveground facility. To date these inspections have not resulted in any citations for material violations of MSHA standards.

We also are subject to the requirements of the U.S. Occupational Safety and Health Act (“OSHA”), and comparable state statutes that regulate the protection of the health and safety of workers. In addition, the OSHA Hazard Communication Standard requires that information be maintained about hazardous materials used or produced in operations and that this information be provided to employees, state and local government authorities and the public. OSHA regulates the customers and users of frac sand and provides detailed regulations requiring employers to protect employees from overexposure to silica through the enforcement of permissible exposure limits and the OSHA Hazard Communication Standard. In March 2016, OSHA published a final rule establishing a more stringent permissible exposure limit for exposure to respirable crystalline silica and other provisions to protect employee, such as requirements for exposure assessment, methods for controlling exposure, respiratory protection, medical surveillance, hazard communication, and recordkeeping. This final rule became effective in June 2016, with compliance required by September 2017 for the construction industry and June 2018 for general industry and maritime. For operations in the oil and gas industry, compliance is required by June 2018, except for engineering controls, which have a compliance date of June 2021.

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Local regulation . As demand for frac sand in the oil and natural gas industry has driven a significant increase in current and expected future production of frac sand, some local communities have 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 are not aware of any proposals for significant increased scrutiny on the part of state or local regulators in the jurisdictions in which we operate or community concerns with respect to our operations that would reasonably be expected to have a material adverse effect on our business, financial condition or results of operations going forward.

Employees

We have no employees. All of our management, administrative and operating functions are performed by employees of Emerge Energy Services GP, LLC, which is our general partner. As of December 31, 2017 , our general partner employed 222 full-time employees who provide these services for us. None of these employees are subject to collective bargaining agreements. We consider our employee relations to be good.

Available Information

We file annual, quarterly, and current reports and other documents with the SEC under the Securities and Exchange Act of 1934. We provide access free of charge to all of our SEC filings, as soon as practicable after they are filed or furnished, through our Internet website located at www.emergelp.com. References to our website addressed in this Annual Report on Form 10-K are provided as a convenience and do not constitute, and should not be viewed as, an incorporation by reference of the information contained on, or available through, the website.

You may also read and copy any of these materials at the SEC's Public Reference Room at 100 F. Street, NE, Room 1580, Washington, D.C. 20549. Information on the operation of the Public Reference Room is available by calling the SEC at 1-800-SEC-0330. Alternatively, the SEC maintains an Internet site ( www.sec.gov ) that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC.

Investors and others should note that we announce material financial information to investors using investor relations websites, press releases, SEC filings and public conference calls and webcasts. We also use Twitter (https://twitter.com/emergelp) as a means of disclosing information about our company, services and other matters. It is possible that the information we disclose could be deemed to be material information. Therefore, we encourage investors, the media and others interested in our company to review the information we post on Twitter.

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ITEM 1A. RISK FACTORS

Limited partner interests are inherently different from capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in the frac sand businesses. You should consider carefully the following risk factors together with all of the other information included in this report in evaluating an investment in our common units.

If any of the following risks were to occur, our business, financial condition or results of operations could be materially adversely affected. In that case, we may be unable to make distributions on our common units, the trading price of our common units could decline, and you could lose all or part of your investment.

Risks Related to Our Business

We may not have sufficient available cash to pay any quarterly distribution on our common units.

We may not have sufficient available cash each quarter to enable us to pay any distributions to our unitholders. For example, the board of directors of our general partner determined that we did not generate sufficient available cash to distribute to our unitholders for each quarter during the year ended December 31, 2017 . Our partnership agreement does not require us to pay distributions on a quarterly basis or otherwise.

In future periods, the amount of cash we can distribute principally depends upon the amount of cash we generate from our operations, which fluctuates from quarter to quarter based on, among other things:


•	the level of production of, demand for, and price of frac sand, particularly in the markets we serve;


•	the fees we charge, and the margins we realize, from our frac sand sales and the other services we provide;


•	changes in laws and regulations (or the interpretation thereof) related to the mining and oil and natural gas industries, silica dust exposure or the environment;


•	the level of competition from other companies;


•	the cost and time required to execute organic growth opportunities;


•	difficulty collecting receivables; and


•	prevailing global and regional economic and regulatory conditions, and their impact on our suppliers and customers.

In addition, the actual amount of cash we have available for distribution depends on other factors, including:


•	the levels of our maintenance capital expenditures and growth capital expenditures;


•	the level of our operating costs and expenses;


•	our debt service requirements and other liabilities;


•	fluctuations in our working capital needs;


•	restrictions contained in our revolving credit facility, the purchase agreement that governs our second lien notes and any other debt agreements to which we are a party;


•	the cost of acquisitions, if any;


•	fluctuations in interest rates;


•	our ability to borrow funds and access capital markets; and


•	the amount of cash reserves established by our general partner.

The amount of distributions that we pay, if any, and the decision to pay any distribution at all, are determined by the board of directors of our general partner. Our revolving credit facility and the purchase agreement that governs our second lien notes also require us to comply with certain financial metrics and liquidity thresholds in order to make quarterly distributions to holders of our common units. Our quarterly distributions, if any, are subject to significant fluctuations based on the above factors.

The amount of cash we have available for distribution to unitholders depends primarily on our cash flow and not solely on profitability.

You should be aware that the amount of cash we have available for distribution depends primarily upon our cash flow, including cash flow from financial reserves and working capital borrowings, and not solely on profitability, which is affected by non-cash items. As a result, we may not be able to make cash distributions during periods in which we record net income.

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The amount of our quarterly cash distributions, if any, may vary significantly both quarterly and annually and will be directly dependent on the performance of our business. Unlike most publicly traded partnerships, we do not have a minimum quarterly distribution or employ structures intended to consistently maintain or increase distributions over time.

Investors who are looking for an investment that will pay regular and predictable quarterly distributions should not invest in our common units. We expect our business performance may be more volatile, and our cash flows may be less stable, than the business performance and cash flows of most publicly traded partnerships. As a result, our quarterly cash distributions may be volatile and may vary quarterly and annually. Unlike most publicly traded partnerships, we do not have a minimum quarterly distribution or employ structures intended to consistently maintain or increase distributions over time. The amount of our quarterly cash distributions is directly dependent on the performance of our business. Because our quarterly distributions will significantly correlate to the cash we generate each quarter after payment of our fixed and variable expenses, quarterly distributions paid to our unitholders may vary significantly from quarter to quarter and may be zero.

The board of directors of our general partner may modify or revoke our cash distribution policy at any time at its discretion. Our partnership agreement does not require us to make any distributions at all.

The board of directors of our general partner adopted a cash distribution policy pursuant to which we distribute all of the available cash we generate each quarter to unitholders of record on a pro rata basis. However, the board may change such policy at any time at its discretion and could elect not to make distributions for one or more quarters. For example, the board of directors of our general partner determined not to make a cash distribution on our common units for each quarter during the year ended December 31, 2017 . Our partnership agreement does not require us to make any distributions at all. Accordingly, investors are cautioned not to place undue reliance on the permanence of such a policy in making an investment decision. Any modification or revocation of our cash distribution policy could substantially reduce or eliminate the amounts of distributions to our unitholders.

We have a history of losses and may continue to incur losses in the future.

For the years ended December 31, 2017 and 2016 , we incurred aggregate losses of $ 6.8 million and $ 72.8 million , respectively. Our loss from continuing operations for the years ended December 31, 2017 and 2016 was $ 3.7 million and $ 113.2 million , respectively, and our loss from discontinued operations was $ 3.1 million for the year ended December 31, 2017 and an income of $ 40.4 million for the year ended December 31, 2016 . There is no assurance that we will operate profitably or will generate positive cash flow in the future. In addition, our operating results in the future may be subject to significant fluctuations due to many factors not within our control, such as the demand for our frac sand products, and the level of competition and general economic conditions.

Our operations are subject to the cyclical nature of our customers' businesses and depend upon the continued demand for crude oil and natural gas.

Our frac sand sales are to customers in the oil and natural gas industry, a historically cyclical industry. This industry was adversely affected by the uncertain global economic climate in the second half of 2008 and in 2009. Natural gas, crude oil and NGL prices declined significantly in the second half of 2014 and have been negatively affected by a combination of factors, including weakening demand, increased production, the decision by the OPEC to keep production levels unchanged and a strengthening in the U.S. dollar relative to most other currencies. Further downward pressure on commodity prices continued throughout 2015 and the first nine months of 2016. Worldwide economic, political and military events, including war, terrorist activity, events in the Middle East and initiatives by OPEC have contributed, and are likely to continue to contribute, to commodity price volatility. Additionally, warmer than normal winters in North America and other weather patterns may adversely impact the short-term demand for oil and natural gas and, therefore, demand for our products.

During periods of economic slowdown and long-term reductions in oil and natural gas prices, oil and natural gas exploration and production companies often reduce their oil and natural gas production rates and also reduce capital expenditures and defer or cancel pending projects, which results in decreased demand for our frac sand. Such developments occur even among companies that are not experiencing financial difficulties. A continued or renewed economic downturn in one or more of the industries or geographic regions that we serve, or in the worldwide economy, could adversely affect our results of operations. In addition, any future decreases in the rate at which oil and natural gas reserves are discovered or developed, whether due to increased governmental regulation, limitations on exploration and drilling activity, a sustained decline in oil and natural gas prices, or other factors, could have a material adverse effect on our business, even in a stronger natural gas and oil price environment.

Our operations are subject to operating risks that are often beyond our control and could adversely affect production levels and costs.

Our mining, processing and production facilities are subject to risks normally encountered in the frac sand industry. These risks include:


•	changes in the price and availability of transportation;

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•	inability to obtain necessary production equipment or replacement parts;


•	inclement or hazardous weather conditions, including flooding, and the physical impacts of climate change;


•	unusual or unexpected geological formations or pressures;


•	unanticipated ground, grade or water conditions;


•	inability to acquire or maintain necessary permits or mining or water rights;


•	labor disputes and disputes with our excavation contractors;


•	late delivery of supplies;


•	changes in the price and availability of natural gas or electricity that we use as fuel sources for our frac sand plants and equipment;


•	technical difficulties or failures;


•	cave-ins or similar pit wall failures;


•	environmental hazards, such as unauthorized spills, releases and discharges of wastes, tank ruptures and emissions of unpermitted levels of pollutants;


•	industrial accidents;


•	changes in laws and regulations (or the interpretation thereof) related to the mining and oil and natural gas industries, silica dust exposure or the environment;


•	inability of our customers or distribution partners to take delivery;


•	reduction in the amount of water available for processing;


•	fires, explosions or other accidents; and


•	facility shutdowns in response to environmental regulatory actions.

Any of these risks could result in damage to, or destruction of, our mining properties or production facilities, personal injury, environmental damage, delays in mining or processing, losses or possible legal liability. Any prolonged downtime or shutdowns at our mining properties or production facilities could have a material adverse effect on us.

Not all of these risks are reasonably insurable, and our insurance coverage contains limits, deductibles, exclusions and endorsements. Our insurance coverage may not be sufficient to meet our needs in the event of loss, and any such loss may have a material adverse effect on us.

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

Frac sand is a proppant used in the completion and re-completion of natural gas and oil wells through hydraulic fracturing. Frac sand is the most commonly used proppant and is less expensive than ceramic proppant, which is also used in hydraulic fracturing to stimulate and maintain oil and natural gas production. A significant shift in demand from frac sand to other proppants, such as ceramic proppants, could have a material adverse effect on our financial condition and results of operations. The development and use of other effective alternative proppants, or the development of new processes to replace hydraulic fracturing altogether, could also cause a decline in demand for the frac sand we produce and could have a material adverse effect on our financial condition and results of operations.

We may be adversely affected by a reduction in horizontal drilling activity or the development of either effective alternative proppants or new processes to replace hydraulic fracturing.

Demand for frac sand is substantially higher in the case of horizontally drilled wells, which allow for multiple hydraulic fractures within the same well bore but are more expensive to develop than vertically drilled wells. The development and use of a cheaper, more effective alternative proppant, a reduction in horizontal drilling activity or the development of new processes to replace hydraulic fracturing altogether, could also cause a decline in demand for the frac sand we produce and could have a material adverse effect on our business, financial condition and results of operations. A reduction in demand for the frac sand we produce may cause our contractual arrangements to become economically unattractive and could have a material adverse effect on our business, financial condition, and results of operations.

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A large portion of our sales is generated by a few large customers, and the loss of our largest customers or a significant reduction in purchases by those customers could adversely affect our operations.

During 2017 , our top five customers represented 59.1% of sales from our continuing operations. Our customers who are not subject to firm contractual commitments may not continue to purchase the same levels of our products in the future due to a variety of reasons. For example, some of our top customers could go out of business or, alternatively, be acquired by other companies that purchase the same products and services provided by us from other third-party providers. Our customers could also seek to capture and develop their own sources of frac sand. In addition, some of our customers may be highly leveraged and subject to their own operating and regulatory risks. If any of our major customers substantially reduces or altogether ceases purchasing our products, we could suffer a material adverse effect on our business, financial condition, results of operations, cash flows, and prospects. In addition, upon the expiration or termination of our existing contracts, we may not be able to enter into new contracts at all or on terms as favorable as our existing contracts. We may also choose to renegotiate our existing contracts on less favorable terms (including with respect to price and volumes) in order to preserve relationships with our customers.

In addition, the long-term sales agreements we have for our frac sand may negatively impact our results of operations. Certain of our long-term agreements are for sales at fixed prices that are adjusted only for certain cost increases. As a result, in periods with increasing frac sand prices, our contract prices may be lower than prevailing industry spot prices. Our long-term sales agreements also contain provisions that allow prices to be adjusted downwards in the event of falling industry prices.

Any material nonpayment or nonperformance by any of our key customers could have a material adverse effect on our business and results of operations and our ability to make cash distributions to our unitholders.

Any material nonpayment or nonperformance by any of our key customers could have a material adverse effect on our revenue and cash flows and our ability to make cash distributions to our unitholders. Our long-term take-or-pay sales agreements with select customers contain provisions designed to compensate us, in part, for our lost margins on any unpurchased volumes; accordingly, in most circumstances, we would be paid less than the price per ton we would receive if our customers purchased the contractual tonnage amounts. Certain of our other long-term frac sand sales agreements provide for minimum tonnage orders by our customers but do not contain pre-determined liquidated damage penalties in the event the customers fail to purchase designated volumes. Instead, we would seek legal remedies against the non-performing customer or seek new customers to replace our lost sales volumes. Certain of our other long-term frac sand supply contracts are efforts-based and therefore do not require the customer to purchase minimum volumes of frac sand from us or contain take-or-pay provisions.

Our different types of contracts with our frac sand customers provide for different potential remedies to us in the event a customer fails to purchase the minimum contracted amount of frac sand in a given period. If we were to pursue legal remedies in the event a customer failed to purchase the minimum contracted amount of sand under a fixed-volume contract or failed to satisfy the take-or-pay commitment under a take-or-pay contract, we may receive significantly less in a judgment or settlement of any claimed breach than we would have received had the customer fully performed under the contract. In the event of any customer's breach, we may also choose to renegotiate any disputed contract on less favorable terms (including with respect to price and volumes) to us to preserve the relationship with that customer. Accordingly, any material nonpayment or performance by our customers could have a material adverse effect on our revenue and cash flows and our ability to make distributions to our unitholders.

Our long-term contracts may preclude us from taking advantage of increasing prices for frac sand or mitigating the effect of increased operational costs during the term of our long-term contracts, even though certain volumes under our long-term contracts are subject to annual fixed price escalators.

The long-term supply contracts we have may negatively impact our results of operations in future periods. Our long-term contracts require our customers to pay a specified price for a specified volume of frac sand over a specified period of time. As a result, in periods with increasing prices, our sales may not keep pace with market prices. Additionally, if our operational costs increase during the terms of our long-term supply contracts, we may not be able to pass any of those increased costs to our customers. If we are unable to otherwise mitigate these increased operational costs, our net income and available cash for distributions could decline.

The credit risks of our concentrated customer base could result in losses.

This concentration of our customers in the energy industry may impact our overall exposure to credit risk as customers may be similarly affected by prolonged changes in economic and industry conditions. If a significant number of our customers experience a prolonged business decline or disruption, we may incur increased exposure to credit risk and bad debts. 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, financial condition, results of operations and ability to pay distributions to our unitholders.

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Certain of our contracts contain provisions requiring us to meet minimum obligations to our customers and suppliers. If we are unable to meet our minimum requirements under these contracts, we may be required to pay penalties or the contract counterparty may be able to terminate the agreement.

In certain instances, we commit to deliver products to our customers prior to production, under penalty of nonperformance. Depending on the contract, our inability to deliver the requisite tonnage of frac sand may permit our customers to terminate the agreement or require us to pay our customers a fee, the amount of which would be based on the difference between the amounts of tonnage contracted for and the amount delivered. We have significant long-term operating leases for railcars, both currently in service and yet to be delivered, under which we would still be obligated to pay despite any future decrease in the number of railcars needed to conduct our operations. Further, our agreement with Canadian National requires us to provide minimum volumes of frac sand for shipping on the Canadian National line. If we do not provide the minimum volume of frac sand for shipping, we will be required to pay a per-ton shortfall penalty, subject to certain exceptions. In addition, under our agreements with sand suppliers, we are obligated to order a minimum amount of wet sand per year or pay fees on the difference between the minimum and the amount we actually order. Similarly, we would be required to make minimum payments to mineral rights owners at certain of our mines in the event we purchase less than the minimum volumes of sand specified under the particular royalty agreement in place. If we are unable to meet our obligations under any of these agreements, we may have to pay substantial penalties or the agreements may become subject to termination, as applicable. In such events, our business, financial condition, and results of operations may be materially adversely affected.

We must effectively manage our production capacity.

To meet rapidly changing demand in the frac sand industry, we must effectively manage our resources and production capacity. During periods of decreasing demand for frac sand, we must be able to appropriately align our cost structure with prevailing market conditions and effectively manage our mining operations. Our ability to rapidly and effectively reduce our cost structure in response to such downturns is limited by the fixed nature of many of our expenses in the near term and by our need to continue our investment in maintaining reserves and production capabilities. Conversely, when upturns occur in the markets we serve, we may have difficulty rapidly and effectively increasing our production capacity or procuring sufficient reserves to meet any sudden increases in the demand for frac sand that could result in the loss of business to our competitors and harm our relationships with our customers. The inability to timely and appropriately adapt to changes in our business environment could have a material adverse effect on our our business, financial condition, results of operations or reputation.

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

The performance, quality, and safety of our products are critical to the success of our business. For instance, our frac sand must meet stringent International Organization for Standardization, or ISO, and API technical specifications, including sphericity, grain size, crush resistance, acid solubility, purity, and turbidity, as well as customer specifications, in order to be suitable for hydraulic fracturing purposes. If our frac sand fails to meet such specifications or our customers' expectations, we could be subject to significant contractual damages or contract terminations and face serious harm to our reputation, and our sales could be negatively affected. The performance, quality, and safety of our products 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, financial condition, results of operations and reputation.

Increasing costs or a lack of dependability or availability of transportation services or infrastructure could have an adverse effect on our ability to deliver our frac sand products at competitive prices.

Because of the relatively low cost of producing frac sand, transportation and handling costs tend to be a significant component of the total delivered cost of sales. The bulk of our currently contracted sales involve our customers also contracting with truck and rail services to haul our frac sand to end users. If there are increased costs under those contracts, and our customers are not able to pass those increases along to end users, our customers may find alternative providers. We have provided fee-based transportation and logistics (including railcar procurement, freight management, and product storage) services for both our spot market and contract customers. Should we fail to properly manage the customer's logistics needs under those instances where we have agreed to provide them, we may face increased costs, and our customers may choose to purchase sand from other suppliers. Labor disputes, derailments, adverse weather conditions or other environmental events, tight railcar leasing markets and changes to rail freight systems could interrupt or limit available transportation services. For example, harsh weather conditions and the continued surge in frac sand demand are currently straining railroad networks across the country and leading to service disruptions. A significant increase in transportation service rates, a reduction in the dependability or availability of transportation services, prolonged rail service disruptions or relocation of our customers’ businesses to areas that are not served by the rail systems accessible from our production facilities could impair our customers’ ability to access our products and our ability to expand our markets or lead our

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customers to seek alternative sources of frac sand, which may have an adverse effect on our business, financial condition, and results of operations.

We face significant competition that may cause us to lose market share and reduce our ability to make distributions to our unitholders.

The frac sand industries are highly competitive. The frac sand 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 specific customer locations than we do. In recent years there has been an increase in the number of small, regional producers servicing the frac sand market due to an increased demand for hydraulic fracturing services and to the growing number of unconventional resource formations being developed in the United States. Should the demand for hydraulic fracturing services decrease or the supply of frac sand available in the market increase, prices in the frac sand market could materially decrease as less-efficient producers exit the market, selling frac sand at below market prices. 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 frac sand reserves to fulfill their proppant requirements, and these other market participants may expand their existing frac sand production capacity, all of which would negatively impact demand for our frac sand products. In addition, increased competition in the frac sand industry could have an adverse impact on our ability to enter into long-term contracts or to enter into contracts on favorable terms.

Our cash flows fluctuate on a seasonal basis and severe weather conditions could have a material adverse effect on our business.

Because raw sand cannot be wet-processed during extremely cold temperatures, frac sand is typically washed only eight months out of the year at our Wisconsin operations. Our inability to wash frac sand year round in Wisconsin results in a seasonal build-up of inventory as we excavate excess sand to build a stockpile that will feed the dry plant during the winter months. This seasonal build-up of inventory causes our average inventory balance to fluctuate from a few weeks in early spring to more than 100 days in early winter. As a result, the cash flows of our continuing sand operations fluctuate on a seasonal basis based on the length of time Wisconsin wet plant operations must remain shut down due to harsh winter weather conditions. We may also be selling frac sand for use in oil and gas-producing basins where severe weather conditions may curtail drilling activities and, as a result, our sales volumes to customers in those areas may be adversely affected. For example, we could experience a decline in volumes sold for the second quarter relative to the first quarter each year due to seasonality of frac sand sales to customers in western Canada as sales volumes are generally lower during the months of April and May due to limited drilling activity as a result of that region's annual thaw. Unexpected winter conditions (if winter comes earlier than expected or lasts longer than expected) may lead to us not having a sufficient sand stockpile to supply feedstock for our dry plant during winter months and result in us being unable to meet our contracted sand deliveries during such time, or may drive frac sand sales volumes down by affecting drilling activity among our customers, each of which could lead to a material adverse effect on our business, financial condition, results of operation and reputation. The inability of our logistics partners, including rail companies, to manage their own operations efficiently during inclement weather could have an effect on our ability to serve our customers where we are relying on our logistics partners to provide certain transportation services.

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

While much of our process water is recycled and recirculated, the mining and processing activities in which we engage at our wet plant facilities require significant amounts of water. During extreme drought conditions, some of our facilities are located in areas that can become water-constrained. We have obtained water rights and have installed high capacity wells on our properties that we currently use to service the activities on our properties, 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 are entitled to use pursuant to our water rights must be determined by the appropriate regulatory authorities in the jurisdictions in which we 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 may be unable to retain all or a portion of such water rights. Such changes in laws, regulations or government policy and related interpretations pertaining to water rights may alter the environment in which we do business, which may negatively affect our financial condition and results of operations.

Similarly, our customers' performance of hydraulic fracturing activities may require the use of large amounts of water. The ability of our customers' to obtain the necessary amounts of water sufficient to perform hydraulic fracturing activities may well depend on those customers ability to acquire water by means of contract, permitting, or spot purchase. The ability of our customers to obtain and maintain sufficient levels of water for these fracturing activities are similarly subject to regulatory authority approvals, changes in applicable laws or regulations, potentially differing interpretations of contract terms, increases in costs to provide such water, and even changes in weather that could make such water resources more scarce.

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We may be unable to grow our cash flows if we are unable to expand our business, which could limit our ability to increase distributions to our unitholders.

A principal focus of our strategy is to continue to grow the per unit distribution on our units by expanding our businesses, particularly our frac sand business. Our future growth will depend upon a number of factors, some of which we cannot control. These factors include our ability to:


•	develop new business and enter into contracts with new customers;


•	retain our existing customers and maintain or expand the level of services we provide them;


•	identify and obtain additional frac sand reserves;


•	recruit and train qualified personnel and retain valued employees;


•	expand our geographic presence;


•	effectively manage our costs and expenses, including costs and expenses related to growth;


•	consummate accretive acquisitions;


•	obtain required debt or equity financing for our existing and new operations;


•	meet customer-specific contract requirements or pre-qualifications;


•	obtain permits from federal, state and local regulatory authorities; and


•	make assumptions about mineral reserves, future production, sales, capital expenditures, operating expenses and costs, including synergies.

If we do not achieve levels of growth expected for our business, the market price of our common units could decline materially.

We may be unable to grow successfully through future acquisitions, and we may not be able to integrate effectively the businesses we may acquire, which may impact our operations and limit our ability to increase distributions to our unitholders.

From time to time, we may choose to make business acquisitions to pursue market opportunities, increase our existing capabilities, and expand into new areas of operations. While we have reviewed acquisition opportunities in the past and will continue to do so in the future, we may not be able to identify attractive acquisition opportunities or successfully acquire identified targets. In addition, we may not be successful in integrating any future acquisitions into our existing operations, which may result in unforeseen operational difficulties or diminished financial performance or require a disproportionate amount of our management's attention. Even if we are successful in integrating future acquisitions into our existing operations, we may not derive the benefits, such as operational or administrative synergies, that we expected from such acquisitions, which may result in the commitment of our capital resources without the expected returns on such capital. Furthermore, competition for acquisition opportunities may escalate, increasing our cost of making acquisitions or causing us to refrain from making acquisitions. Our inability to make acquisitions, or to integrate successfully future acquisitions into our existing operations, may adversely impact our operations and limit our ability to increase distributions to our unitholders.

Growing our business by constructing new plants and facilities subjects us to construction risks as well as market risks relating to insufficient demand for the services of such plants and facilities upon completion thereof.

One of the ways we intend to grow our business is through the construction of new dry plants, wet plants, and transload facilities in our continuing sand operations. The construction of such facilities requires the expenditure of significant amounts of capital, which may exceed our resources, and involves numerous regulatory, environmental, political, and legal uncertainties. If we undertake these projects, we may not be able to complete them on schedule or at all or at the budgeted cost. Moreover, our revenues may not increase upon the expenditure of funds on a particular project. For instance, if we build a new plant or facility, the construction will occur over an extended period of time, and we will not receive any material increases in revenues until at least after completion of the project, if at all. Moreover, we may construct new plants or facilities to capture anticipated future demand in a region in which anticipated market conditions do not materialize or for which we are unable to acquire new customers. As a result, new plants or facilities may not be able to attract enough demand to achieve our expected investment return, which could materially and adversely affect our results of operations and financial condition.

Our ability to grow in the future is dependent on our ability to access external growth capital.

We may distribute all of our available cash after expenses and prudent operating reserves to our unitholders. We expect that we will rely primarily upon external financing sources, including borrowings under our revolving credit facility and the issuance of debt and equity securities, to maintain our asset base and fund growth capital expenditures. However, we may not be able to obtain

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equity or debt financing on terms favorable to us, or at all. To the extent we are unable to efficiently finance growth externally, our cash distribution policy will significantly impair our ability to grow. In addition, because we may distribute all of our available cash, we may not grow as quickly as businesses that reinvest their available cash to expand ongoing operations. To the extent we issue additional units in connection with other growth capital expenditures, such issuances may result in significant dilution to our existing unitholders and the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level. There are no limitations in our partnership agreement on our ability to issue additional units, including units ranking senior to the common units. The incurrence of borrowings or other debt by us to finance our growth strategy would result in interest expense, which in turn would affect the available cash that we have to distribute to our unitholders.

Our debt levels may limit our flexibility in obtaining additional financing, pursuing other business opportunities and paying distributions.

In January 2018, we entered into a $75.0 million asset-based revolving credit facility with outstanding borrowings of $2.5 million as of February 22, 2018 , as well as $215.0 million aggregate principal amount of notes currently outstanding under our second lien note purchase agreement. As of January 31, 2018, our borrowing base under the revolving credit facility was in excess of $75 million, and therefore available borrowings are limited by total commitments from lenders. Our ability to incur additional debt is subject to limitations under our revolving credit facility and the purchase agreement that governs our second lien notes. Our level of debt has important consequences to us, including the following:


•	our ability to obtain additional financing, if necessary, for operating working capital, capital expenditures, acquisitions or other purposes may be impaired by our debt level, or such financing may not be available on favorable terms;


•	we need a portion of our cash flow to make payments on our indebtedness, reducing the funds that would otherwise be available for operations, future business opportunities and distributions; and


•	our debt level makes us more vulnerable than our competitors with less debt to competitive pressures or a downturn in our business or the economy generally.

Our ability to service our debt depends upon, among other things, our future financial and operating performance, which is affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. In addition, our ability to service our debt under our revolving credit facility and the purchase agreement that governs our second lien notes depends on market interest rates, since the interest rates applicable to our borrowings fluctuate with movements in interest rate markets. If our operating results are not sufficient to service our current or future indebtedness, we will be forced to take actions such as reducing distributions, reducing or delaying our business activities, acquisitions, investments or capital expenditures, selling assets, restructuring or refinancing our debt, or seeking additional equity capital. We may be unable to effect any of these actions on satisfactory terms, or at all.

Restrictions in our revolving credit facility and the purchase agreement that governs our second lien notes limit our ability to capitalize on acquisition and other business opportunities.

The operating and financial restrictions and covenants in our revolving credit facility, the purchase agreement that governs our second lien notes 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 and the purchase agreement that governs our second lien notes restrict or limit our ability to:


•	grant liens;


•	incur additional indebtedness;


•	engage in a merger, consolidation or dissolution;


•	enter into transactions with affiliates;


•	sell or otherwise dispose of assets, businesses and operations;


•	materially alter the character of our business;


•	make acquisitions, investments and capital expenditures; and


•	make distributions to our unitholders.

Furthermore, our revolving credit facility and the purchase agreement that governs our second lien notes contain certain operating and financial covenants. Our ability to comply with the covenants and restrictions contained in our revolving credit facility and the purchase agreement that governs our second lien notes 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 a significant portion of our indebtedness

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may become immediately due and payable. We might not have, or be able to obtain, sufficient funds to make these accelerated payments. Any subsequent replacement of our revolving credit facility, our second lien notes or any new indebtedness could have similar or greater restrictions.

We may have difficulty maintaining compliance with the covenants and ratios required under our revolving credit facility and the purchase agreement that governs our second lien notes, which currently include covenants to maintain certain levels of liquidity and meet certain threshold ratios for leverage and fixed charges. Failure to maintain compliance with these financial covenants could adversely affect our operations, financial condition and ability to make distributions to our unitholders.

We depend on our revolving credit facility for future capital needs and to fund our operations and capital expenditures, as necessary. We are required to comply with certain financial covenants and ratios under our revolving credit facility as well as the purchase agreement that governs our second lien notes. 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. Our revolving credit facility and the purchase agreement that governs our second lien notes require us, among other things, to maintain a minimum liquidity requirement of $20 million at all times, to meet certain thresholds for total leverage ratio and fixed charge coverage ratio and to limit our capital expenditures, subject to certain availability thresholds. We are currently in compliance with the covenants in our revolving credit facility and the purchase agreement that governs our second lien notes.

Our failure to comply with any of the covenants in our revolving credit facility and the purchase agreement that governs our second lien notes could result in a default, which could cause all of our existing indebtedness to become immediately due and payable. 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 our acquisitions, strategic growth projects, portions of our current operations and other activities. A lack of capital could result in a decrease in the operations of our sand business, subject us to claims of breach under customer and supplier contracts and may force us to sell some of our assets on an untimely or unfavorable basis, each of which could adversely affect our results of operations, financial condition and ability to make distributions to our unitholders.

If we are unable to generate enough cash flow from operations to service our indebtedness or are unable to use future borrowings to refinance our indebtedness or fund other capital needs, we may have to undertake alternative financing plans, which may have onerous terms or may be unavailable.

We cannot assure you that our business will generate sufficient cash flow from operations to service our outstanding indebtedness, or that future borrowings will be available to us in an amount sufficient to enable us to pay our indebtedness or to fund our other capital needs. If we do not generate sufficient cash flow from operations to satisfy our debt obligations, we may have to undertake alternative financing plans, such as:


•	refinancing or restructuring all or a portion of our debt;


•	obtaining alternative financing;


•	selling assets;


•	reducing or delaying capital investments;


•	seeking to raise additional capital; or


•	revising or delaying our strategic plans.

However, we cannot assure you that we would be able to implement alternative financing plans, if necessary, on commercially reasonable terms or at all, or that undertaking alternative financing plans, if necessary, would allow us to meet our debt obligations and capital requirements or that these actions would be permitted under the terms of our various debt instruments.

Our inability to generate sufficient cash flow to satisfy our debt obligations or to obtain alternative financing could materially and adversely affect our business, financial condition, results of operations, cash flows, and prospects. Any failure to make scheduled payments of interest and principal on our outstanding indebtedness would likely result in a reduction of our credit rating, which could harm our ability to incur additional indebtedness on acceptable terms. Further, if for any reason we are unable to meet our debt service and repayment obligations, we would be in default under the terms of the agreements governing our debt, which would allow our creditors at that time to declare all outstanding indebtedness to be due and payable (which would in turn trigger cross-acceleration or cross-default rights between the relevant agreements), the lenders under our revolving credit facility could terminate their commitments to lend any additional amounts, and the lenders under our revolving credit facility and the purchase agreement that governs our second lien notes could foreclose against our assets securing their borrowings and we could be forced into bankruptcy or liquidation. If the amounts outstanding under our revolving credit facility, the purchase agreement that governs our second lien notes or any of our other indebtedness were to be accelerated, we cannot assure you that our assets would be sufficient to repay in full the money owed to the lenders or to our other debt holders.

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Despite our current level of indebtedness, we may still be able to incur substantially more debt. This could further exacerbate the risks associated with our current indebtedness.

We and our subsidiaries may be able to incur substantial additional indebtedness in the future, subject to certain limitations, including those under our revolving credit facility and the purchase agreement that governs our second lien notes. If new debt is added to our current debt levels, the related risks that we now face could increase. Our level of indebtedness could, for instance, prevent us from engaging in transactions that might otherwise be beneficial to us or from making desirable capital expenditures. This could put us at a competitive disadvantage relative to other less leveraged competitors that have more cash flow to devote to their operations. In addition, the incurrence of additional indebtedness could make it more difficult to satisfy our existing financial obligations.

Our ability to manage and grow our business effectively may be adversely affected if we lose management or operational personnel.

We depend on the continuing efforts of our executive officers. The departure of any of our executive officers could have a significant negative effect on our business, operating results, financial condition and on our ability to compete effectively in the marketplace.

Additionally, our ability to hire, train and retain qualified personnel will continue to be important and will become more challenging as we grow and if energy industry market conditions continue to be positive. When general industry conditions are good, the competition for experienced operational personnel increases as other energy and manufacturing companies' personnel needs increase. Our ability to grow or even to continue our current level of service to our current customers will be adversely impacted if we are unable to successfully hire, train and retain these important personnel.

Inaccuracies in our estimates of mineral reserves could result in lower than expected sales and higher than expected costs.

We base our mineral reserve estimates on engineering, economic, and geological data assembled and analyzed by our engineers and geologists, which are reviewed by outside firms. However, sand reserve estimates are necessarily imprecise and depend to some extent on statistical inferences drawn from available drilling data, which may prove unreliable. There are numerous uncertainties inherent in estimating quantities and qualities of mineral reserves and in estimating costs to mine recoverable reserves, including many factors beyond our control. Estimates of recoverable mineral reserves necessarily depend on a number of factors and assumptions, all of which may vary considerably from actual results, such as:


•	geological and mining conditions and/or effects from prior mining that may not be fully identified by available data or that may differ from experience;


•	assumptions concerning future prices of frac sand products, operating costs, mining technology improvements, development costs and reclamation costs; and


•	assumptions concerning future effects of regulation, including our ability to obtain required permits and the imposition of taxes by governmental agencies.

Any inaccuracy in our estimates related to our mineral reserves could result in lower than expected sales and higher than expected costs and have an adverse effect on our cash available for distribution.

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 each of our sand facilities. A decision by a governmental agency or other third party to deny or delay issuing a new or renewed permit, water right or approval, or to revoke or substantially modify an existing permit, water right or approval, could have a material adverse effect on our ability to continue operations at the affected facility. Expansion of our existing operations is also predicated on securing the necessary environmental or other permits, water rights or approvals, which we may not receive in a timely manner or at all.

We are subject to compliance with stringent environmental laws and regulations that may expose us to substantial costs and liabilities.

Our sand and mining operations are subject to increasingly stringent and complex federal, state and local environmental laws, regulations and standards governing the discharge of materials into the environment or otherwise relating to environmental protection. These laws, regulations and standards impose numerous obligations that are applicable to our operations, including the acquisition of permits to conduct regulated activities; the incurrence of significant capital expenditures to limit or prevent releases of materials from our processors, terminals, and related facilities; and the imposition of remedial actions or other liabilities for pollution conditions caused by our operations or attributable to former operations. Numerous governmental authorities, such as the EPA, and similar state agencies, have the power to enforce compliance with these laws, regulations and standards and the permits issued under them, often requiring difficult and costly actions.

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Failure to comply with environmental laws, regulations, standards, permits, and orders may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations, and the issuance of injunctions limiting or preventing some or all of our operations. Certain environmental laws impose strict liability for the remediation of spills and releases of oil and hazardous substances that could subject us to liability without regard to whether we were negligent or at fault. In addition, changes in environmental laws and regulations occur frequently, and any such changes that result in more stringent and costly waste handling, storage, transport, disposal or remediation requirements with respect to our operations or more stringent or costly well drilling, construction, completion or water management activities with respect to our customers' operations could adversely affect our operations, financial results and cash available for distribution.

Increasingly stringent environmental laws and regulations, unanticipated remediation obligations or emissions control expenditures and claims for penalties or damages could result in substantial costs and liabilities, and our ability to make distributions to our unitholders could suffer as a result. Neither the owners of our general partner nor their affiliates will indemnify us for any environmental liabilities, including those arising from non-compliance or pollution, that may be discovered at, on or under, or arise from, our operations or assets. As such, we can expect no economic assistance from any of them in the event that we are required to make expenditures to investigate, correct or remediate any petroleum hydrocarbons, hazardous substances, wastes or other materials. Please see “Environmental and Occupational Health and Safety Regulations” for more detail regarding the environmental and occupational health and safety rules that impact our operations.

Government action on climate change could result in increased compliance costs for us and our customers.

Methane, a primary component of natural gas, and carbon dioxide, a byproduct of the burning of natural gas, are examples of greenhouse gases (“GHGs”). In recent years, the U.S. Congress has considered legislation to reduce emissions of GHGs. 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, almost half of the states have begun to address GHG emissions, primarily through the planned 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 CAA. For example, the EPA has adopted rules requiring the reporting of GHG emissions in the United States from specified large GHG emission sources. The EPA also has adopted rules establishing construction and operating permit requirements for certain large stationary sources of GHG emissions that are already potential major sources of critical pollutants.

Further, in December 2015, over 190 countries, including the United States, reached an agreement to reduce global greenhouse gas emissions. The agreement entered into force in November 2016 after more than 70 countries, including the United States, ratified or otherwise consented to be bound by the agreement. To the extent the United States or any other country implements this agreement or impose other climate change regulations on the oil and gas industry, it could have an adverse direct or indirect effect on our business.

Mine closures entail substantial costs, and if we close one or more of our mines sooner than anticipated, our results of operations may be adversely affected.

We base our assumptions regarding the life of our mines on detailed studies that we perform from time to time, but our studies and assumptions do not always prove to be accurate. If we close any of our mines sooner than expected, sales will decline unless we are able to increase production at any of our other mines, which may not be possible.

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 decommissioning and removal of facilities and equipment, re-grading, prevention of erosion and other forms of water pollution, re-vegetation and post-mining monitoring and 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 mine closures for which we will be responsible were later determined to be insufficient, or if we were required to expedite the timing for performance of mine closure activities as compared to estimated timelines, our business, results of operations and financial condition could be adversely affected.

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Federal, state and local legislative and regulatory initiatives relating to hydraulic fracturing and the potential for related regulatory action or litigation could result in increased costs and additional operating restrictions or delays for our customers, which could negatively impact our business, financial condition and results of operations and cash flows.

A significant portion of our business supplies frac sand to oil and natural gas industry customers performing hydraulic fracturing activities. Increased regulation of hydraulic fracturing may adversely impact our business, financial condition, and results of operations.

Hydraulic fracturing involves the injection of water, sand, and chemicals under pressure into the formation to stimulate gas production. Legislation to amend the Safe Drinking Water Act (the “SDWA”) to repeal the exemption for hydraulic fracturing from the definition of “underground injection” and require federal permitting and regulatory control of hydraulic fracturing, as well as legislative proposals to require disclosure of the chemical constituents of the fluids used in the fracturing process, were proposed in recent sessions of Congress. We cannot predict whether any such legislation will ever be enacted and, if so, what its provisions would be. Scrutiny of hydraulic fracturing activities continues in other ways, with the EPA having released a final report regarding the impacts of hydraulic fracturing on drinking water resources in 2016. The report concluded that certain activities associated with hydraulic fracturing may impact drinking water resources under certain circumstances. In addition, the U.S. Department of energy released a series of recommendations for improving the safety of the process in 2011. Further, the EPA and the U.S. Department of the Interior (the “DOI”) have proposed and adopted new regulations for certain aspects of the process. For example, the EPA finalized effluent limitations for the treatment and discharge of wastewater resulting from hydraulic fracturing. The DOI adopted rules that require disclosure of chemicals used in hydraulic fracturing activities upon federal and Indian lands and also would strengthen standards for well-bore integrity and the management of fluids that return to the surface during and after fracturing operations on federal and Indian lands (although implementation of this rule has been stayed pending the resolution of legal challenges).

In addition, various state, local and foreign governments have implemented, or are considering, increased regulatory oversight of hydraulic fracturing through additional permitting requirements, operational restrictions, disclosure requirements and temporary or permanent bans on hydraulic fracturing in certain areas, such as environmentally sensitive watersheds. For example, many states - including the major oil and gas producing states of North Dakota, Ohio, Oklahoma, Pennsylvania, Texas, and West Virginia - have imposed disclosure requirements on hydraulic fracturing well owners and operators. The availability of public information regarding the constituents of hydraulic fracturing fluids could make it easier for third parties opposing the hydraulic fracturing process to initiate individual or class action legal proceedings based on allegations that specific chemicals used in the hydraulic fracturing process could adversely affect groundwater and drinking water supplies or otherwise cause harm to human health or the environment. Moreover, disclosure to third parties or to the public, even if inadvertent, of our customers' proprietary chemical formulas could diminish the value of those formulas and result in competitive harm to our customers, which could indirectly impact our business, financial condition and results of operations. The adoption of new laws or regulations at the federal, state, local or foreign levels imposing reporting obligations on, or otherwise limiting or delaying, the hydraulic fracturing process could make it more difficult to complete natural gas wells in shale formations, 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 frac sand products. In addition, heightened political, regulatory, and public scrutiny of hydraulic fracturing practices could potentially expose us or our customers to increased legal and regulatory proceedings, and any such proceedings could be time-consuming, costly or result in substantial legal liability or significant reputational harm. Any such developments could have a material adverse effect on our business, financial condition, and results of operations, whether directly or indirectly. For example, 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 in the geographic areas we serve.

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 and operating equipment. We are also subject to standards imposed by MSHA and other federal and state agencies relating to workplace exposure to crystalline silica. 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.

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We and our customers are subject to other extensive regulations, including licensing, protection of plant and wildlife endangered and threatened species, 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 threatened and endangered species protection, jurisdictional 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 of our frac sand and other mineral deposits and 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 mining and processing activities may have on the environment, individually or in the aggregate, including on public lands. 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 non-governmental organizations, or other third parties or delay in the environmental review and permitting process also could impair or delay 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 frac sand products. 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.

Terrorist attacks, the threat of terrorist attacks, hostilities in the Middle East, or other sustained military campaigns may adversely impact our results of operations.

The long-term impact of terrorist attacks, such as the attacks that occurred on September 11, 2001, and the magnitude of the threat of future terrorist attacks on the energy industry in general and on us in particular are not known at this time. Uncertainty surrounding hostilities in the Middle East or other sustained military campaigns may affect our operations in unpredictable ways, including disruptions of markets for frac sand and the possibility that infrastructure facilities and pipelines could be direct targets of, or indirect casualties of, an act of terror. Changes in the insurance markets attributable to terrorist attacks may make certain types of insurance more difficult for us to obtain. Moreover, the insurance that may be available to us may be significantly more expensive than our existing insurance coverage. Instability in the financial markets as a result of terrorism or war could also affect our ability to raise capital.

A failure in our operational and communications systems, loss of power, natural disasters, or cyber security attacks on any of our facilities, or those of third-parties, may adversely affect our financial results.

Our business is dependent upon our operational systems to process a large amount of data and a substantial number of transactions. If any of our financial, operational or other data processing systems fail or have other significant shortcomings, our financial results could be adversely affected. Our financial results could also be adversely affected if an employee causes our operational or financial systems to fail, either as a result of inadvertent error or by deliberately tampering with or manipulating our operational systems. In addition, dependence upon automated systems may further increase the risk that operational system flaws, employee tampering or manipulation of those systems will result in losses that are difficult to detect.

Due to technology advances, we have become more reliant on technology to help increase efficiency in our business. We use computer programs to help run our financial and operations processes, and this may subject our business to increased risks. Any future cyber security attacks that affect our facilities, communications systems, our customers or any of our financial data could have a material adverse effect on our business. In addition, cyber-attacks on our customer and employee data may result in a financial loss and may negatively impact our reputation. We do not maintain specialized insurance for possible liability resulting from a cyber-attack on our assets that may shut down all or part of our business. Third-party systems on which we rely could also suffer operational system failure. Any of these occurrences could disrupt our business, result in potential liability or reputational damage or otherwise have an adverse effect on our financial results.

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Risks Inherent in an Investment in Us

Holders of our common units have limited voting rights and are not entitled to elect our general partner or its directors.

Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management's decisions regarding our business. Unitholders have no right on an annual or ongoing basis to elect our general partner or its board of directors. Insight Equity is the majority owner of our general partner and has the right to appoint our general partner's entire board of directors, including our independent directors. If the unitholders are dissatisfied with the performance of our general partner, they have little ability to remove our general partner. As a result of these limitations, the price at which the common units trade may be diminished because of the absence or reduction of a takeover premium in the trading price. Our partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders' ability to influence the manner or direction of management.

Insight Equity owns the majority of and controls our general partner, which has sole responsibility for conducting our business and managing our operations. Our general partner and its affiliates, including Insight Equity, have conflicts of interest with us and limited duties, and they may favor their own interests to the detriment of us and our common unitholders.

Insight Equity owns the majority of and controls our general partner and appoints all of the officers and directors of our general partner, some of whom are officers and directors of Insight Equity. Although our general partner has a duty to manage us in a manner that is beneficial to us and our unitholders, the directors and officers of our general partner have a fiduciary duty to manage our general partner in a manner that is beneficial to its owners. Conflicts of interest may arise between Insight Equity and our general partner, on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts of interest, our general partner may favor its own interests and the interests of Insight Equity and the other owners of our general partner over our interests and the interests of our common unitholders. These conflicts include the following situations, among others:


•	neither our partnership agreement nor any other agreement requires Insight Equity to pursue a business strategy that favors us or utilizes our assets or dictates what markets to pursue or grow;


•	our general partner is allowed to take into account the interests of parties other than us, such as Insight Equity, in resolving conflicts of interest;


•	our partnership agreement replaces the fiduciary duties that would otherwise be owed by our general partner with contractual standards governing its duties, limits our general partner's liabilities and restricts the remedies available to our unitholders for actions that, without these limitations, might constitute breaches of its fiduciary duty;

•

our partnership agreement provides that whenever our general partner makes a determination or takes, or declines to take, any other action in its capacity as our general partner, our general partner is required to make such determination, or take or decline to take such other action, in good faith, meaning that it subjectively believed that the decision was in the best interests of our partnership, and, except as specifically provided by our partnership agreement, will not be subject to any other or different standard imposed by our partnership agreement, Delaware law, or any other law, rule or regulation, or at equity;


•	except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval;


•	our general partner determines the amount and timing of asset purchases and sales, capital expenditures, borrowings, issuances of additional partnership securities and the creation, reduction or increase of reserves, each of which can affect the amount of cash that is distributed to our unitholders;


•	our general partner determines which of the costs it incurs on our behalf are reimbursable by us;


•	our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or from entering into additional contractual arrangements with any of these entities on our behalf;


•	our general partner intends to limit its liability regarding our obligations;


•	our general partner may exercise its right to call and purchase all of the common units not owned by it and its affiliates if they own more than 80% of the common units;


•	our general partner controls the enforcement of its and its affiliates' obligations to us; and


•	our general partner decides whether to retain separate counsel, accountants or others to perform services for us.

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Our general partner limits its liability regarding our obligations.

Our general partner limits its liability under contractual arrangements so that the counterparties to such arrangements have recourse only against our assets, and not against our general partner or its assets. Our general partner may therefore cause us to incur indebtedness or other obligations that are nonrecourse to our general partner. Our partnership agreement provides that any action taken by our general partner to limit its liability is not a breach of our general partner's duties, even if we could have obtained more favorable terms without the limitation on liability. In addition, we are obligated to reimburse or indemnify our general partner to the extent that it incurs obligations on our behalf. Any such reimbursement or indemnification payments would reduce the amount of cash otherwise available for distribution to our unitholders.

Our partnership agreement replaces our general partner's fiduciary duties to holders of our common units with contractual standards governing its duties.

Our partnership agreement contains provisions that eliminate the fiduciary standards to which our general partner would otherwise be held by state fiduciary duty law and replace those duties with several different contractual standards. For example, our partnership agreement permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner, free of any duties to us and our unitholders other than the implied contractual covenant of good faith and fair dealing, which means that a court will enforce the reasonable expectations of the partners where the language in the partnership agreement does not provide for a clear course of action. This provision entitles our general partner to consider only the interests and factors that it desires and relieves it of any duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or our limited partners. Examples of decisions that our general partner may make in its individual capacity include:


•	how to allocate business opportunities among us and its affiliates;


•	whether to exercise its limited call right;


•	whether to seek approval of the resolution of a conflict of interest by the conflicts committee of the board of directors of our general partner;


•	how to exercise its voting rights with respect to the units it owns; and


•	whether or not to consent to any merger or consolidation of the partnership or amendment to the partnership agreement.

Our common unitholders have agreed to become bound by the provisions in the partnership agreement, including the provisions discussed above.

Our partnership agreement restricts the remedies available to holders of our common units for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.

Our partnership agreement contains provisions that restrict the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty under state fiduciary duty law. For example, our partnership agreement:

•

provides that whenever our general partner makes a determination or takes, or declines to take, any other action in its capacity as our general partner, our general partner is required to make such determination, or take or decline to take such other action, in good faith, meaning it subjectively believed that the decision was in the best interest of our partnership, and except as specifically provided by our partnership agreement, will not be subject to any other or different standard imposed by our partnership agreement, Delaware law, or any other law, rule or regulation, or at equity;


•	provides that our general partner will not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as such decisions are made in good faith;

•

provides that our general partner and its officers and directors will not be liable for monetary damages to us, our limited partners or their assignees resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or its officers and directors, as the case may be, acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was unlawful; and


•	provides that our general partner will not be in breach of its obligations under our partnership agreement (including any duties to us or our unitholders) if a transaction with an affiliate or the resolution of a conflict of interest is:


•	approved by the conflicts committee of the board of directors of our general partner, although our general partner is not obligated to seek such approval;


•	approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner or any of its affiliates;

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•	determined by the board of directors of our general partner to be on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or


•	determined by the board of directors of our general partner to be “fair and reasonable” to us, taking into account the totality of the relationships among the parties involved, including other transactions that may be particularly favorable or advantageous to us.

In connection with a situation involving a transaction with an affiliate or a conflict of interest, any determination by our general partner must be made in good faith. If an affiliate transaction or the resolution of a conflict of interest is not approved by our common unitholders or the conflicts committee and the board of directors of our general partner determines that the resolution or course of action taken with respect to the affiliate transaction or conflict of interest satisfies either of the standards set forth in bullets three and four above, then it will be presumed that, in making its decision, the board of directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. In this context, members of the board of directors of our general partner will be conclusively deemed to have acted in good faith if it subjectively believed that either of the standards set forth in bullets three and four above was satisfied.

Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our common units.

Unitholders' voting rights are further restricted by a provision of our partnership agreement providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than our general partner, its affiliates, their direct transferees and their indirect transferees approved by our general partner (which approval may be granted in its sole discretion) and persons who acquired such units with the prior approval of our general partner, cannot vote on any matter.

Our general partner interest or the control of our general partner may be transferred to a third party without unitholder consent.

Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, our partnership agreement does not restrict the ability of Insight Equity to transfer all or a portion of its ownership interest in our general partner to a third party. The new owner of our general partner would then be in a position to replace the board of directors and officers of our general partner with its own designees and thereby exert significant control over the decisions made by the board of directors and officers.

An increase in interest rates may cause the market price of our common units to decline.

Like all equity investments, an investment in our common units is subject to certain risks. In exchange for accepting these risks, investors may expect to receive a higher rate of return than would otherwise be obtainable from lower-risk investments. Accordingly, as interest rates rise, the ability of investors to obtain higher risk-adjusted rates of return by purchasing government-backed debt securities may cause a corresponding decline in demand for riskier investments generally, including yield-based equity investments such as publicly traded partnership interests. Reduced demand for our common units resulting from investors seeking other more favorable investment opportunities may cause the trading price of our common units to decline.

We may issue additional units without your approval, which would dilute your existing ownership interests.

Our partnership agreement does not limit the number of additional limited partner interests that we may issue at any time without the approval of our unitholders. The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:


•	our existing unitholders' proportionate ownership interest in us will decrease;


•	the amount of cash available for distribution on each unit may decrease;


•	the ratio of taxable income to distributions may increase;


•	the relative voting strength of each previously outstanding unit may be diminished; and


•	the market price of the common units may decline.

Our general partner has a call right that may require you to sell your units at an undesirable time or price.

If at any time our general partner and its affiliates own more than 80% of the common units, our general partner will have the right, which it may assign to any of its affiliates or to us, but not the obligation, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price that is not less than their then-current market price, as calculated pursuant to the terms of our partnership agreement. As a result, you may be required to sell your common units at an undesirable time or price and may not receive any return or a negative return on your investment. You may also incur a tax liability upon a sale of your units.

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Your liability may not be limited if a court finds that unitholder action constitutes control of our business.

A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. Our partnership is organized under Delaware law, and we conduct business in a number of other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the other states in which we do business. You could be liable for any and all of our obligations as if you were a general partner if a court or government agency were to determine that:


•	we were conducting business in a state but had not complied with that particular state's partnership statute; or


•	your right to act with other unitholders to remove or replace our general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constitute “control” of our business.

Unitholders may have liability to repay distributions that were wrongfully distributed to them.

Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to you if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of an impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Substituted limited partners are liable both for the obligations of the assignor to make contributions to the partnership that were known to the substituted limited partner at the time it became a limited partner and for those obligations that were unknown if the liabilities could have been determined from the partnership agreement. Neither liabilities to partners on account of their partnership interest nor liabilities that are non-recourse to the partnership are counted for purposes of determining whether a distribution is permitted.

The New York Stock Exchange, or NYSE, does not require a publicly traded partnership like us to comply with certain of its corporate governance requirements.

Because we are a publicly traded partnership, the NYSE does not require us to have a majority of independent directors on our general partner's board of directors or to establish a compensation committee or a nominating and corporate governance committee. Accordingly, unitholders do not have the same protections afforded to certain corporations that are subject to all of the NYSE corporate governance requirements.

If we cannot meet the New York Stock Exchange (“NYSE”) continued listing requirements, the NYSE may delist our common units which would have an adverse impact on the liquidity and market price of our common units.

Our common stock is currently listed on the NYSE. In the future, we may not be able to meet the continued listing requirements of the NYSE. As previously disclosed in our press release dated May 20, 2016, and our Notification of Late Filing on Form 12b-25 filed with the Securities and Exchange Commission on May 11, 2016, we were not able to file our Quarterly Report on Form 10-Q for the period ended March 31, 2016, in a timely manner. On May 17, 2016, we received a letter from the New York Stock Exchange Regulation, Inc. informing us that, as a result of our failure to timely file our Form 10-Q for the period ended March 31, 2016, we were subject to the procedures specified in Section 802.01E (SEC Annual Report Timely Filing Criteria) of the NYSE’s Listed Company Manual. We are in compliance with this NYSE requirement following the filing of our quarterly reports on Form 10-Q for the periods ended March 31, 2016, and June 30, 2016, on September 12, 2016. In addition, the continued listing requirements on the NYSE require, among other things; (i) that the average closing price of our common units be above $1.00 over 30 consecutive trading days and (ii) that our market capitalization be not less than $15 million over 30 consecutive trading days. If in the future we are unable to satisfy the NYSE criteria for continued listing, our common units would be subject to delisting. A delisting of our common units could negatively impact us by reducing the liquidity and market price of our common units, reducing the number of investors willing to hold or acquire our common units, which could negatively impact our ability to raise equity financing.

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

Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud, and operate successfully as a public company. If we cannot provide reliable financial reports or prevent fraud, our reputation and operating results would be harmed. We cannot be certain that we will be able to maintain adequate controls over our financial processes and reporting in the future or that we will be able to comply with our obligations under Section 404 of the Sarbanes Oxley Act of 2002. Any failure to maintain effective internal controls, or difficulties encountered in implementing or improving our internal controls, could harm our operating results or cause us to fail to meet our reporting obligations. Ineffective internal controls could also cause investors to lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our units.

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Tax Risks to Common Unitholders

Our tax treatment depends on our status as a partnership for federal income tax purposes. If the IRS were to treat us as a corporation for federal income tax purposes, which would subject us to entity-level taxation, then our cash available for distribution to our unitholders would be substantially reduced.

The anticipated after-tax economic benefit of an investment in the common units depends largely on our being treated as a partnership for federal income tax purposes. Despite the fact that we are a limited partnership under Delaware law, it is possible in certain circumstances for a partnership such as ours to be treated as a corporation for federal income tax purposes. Although we do not believe based upon our current operations that we will be so treated, a change in our business or a change in current law could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity.

If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 21%, and would likely pay state and local income tax at varying rates. Distributions would generally be taxed again as corporate dividends (to the extent of our current and accumulated earnings and profits), and no income, gains, losses, deductions, or credits would flow through to you. Because a tax would be imposed upon us as a corporation, our cash available for distribution to you would be substantially reduced. Therefore, if we were treated as a corporation for federal income tax purposes, there would be a material reduction in the anticipated cash flow and after-tax return to our unitholders, likely causing a substantial reduction in the value of our common units.

If we were subjected to a material amount of additional entity-level taxation by individual states, it would reduce our cash available for distribution to our unitholders.

Changes in current state law may subject us to additional entity-level taxation by individual states. Several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. Imposition of any such taxes may substantially reduce the cash available for distribution to you and, therefore, negatively impact the value of and investment in our common units.

The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.

The present federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative, or judicial interpretation at any time. For example, from time to time, the U.S. government considers substantive changes to the existing federal income tax laws that affect publicly traded partnerships, including the elimination of the qualifying income exception upon which we rely for our treatment as a partnership for federal income tax purposes.

Any modification to the federal income tax laws and interpretations thereof may or may not be retroactively applied and could make it more difficult or impossible to meet the exception for us to be treated as a partnership for federal income tax purposes. We are unable to predict whether any of these changes or other proposals will ultimately be enacted. However, it is possible that a change in law could affect us, and any such changes could negatively impact the value of an investment in our common units.

Our unitholders' share of our income is taxable to them for federal income tax purposes even if they do not receive any cash distributions from us.

Because a unitholder is treated as a partner to whom we allocate taxable income which could be different in amount than the cash we distribute, a unitholder's allocable share of our taxable income is taxable to it, which may require the payment of federal income taxes and, in some cases, state and local income taxes, on its share of our taxable income even if it receives no cash distributions from us. For example, a gain on the sale of any of our assets may result in a unitholder being allocated taxable income without receiving a corresponding cash distribution from us. Our unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from that income.

If the IRS contests the federal income tax positions we take, the market for our common units may be adversely impacted and the cost of any IRS contest will reduce our cash available for distribution to our unitholders.

The IRS has made no determination with respect to our treatment as a partnership for federal income tax purposes. The IRS may adopt positions that differ from the positions we take, and the IRS's positions may ultimately be sustained. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take and such positions may not ultimately be sustained. A court may not agree with some or all the positions we take. Any contest with the IRS, and the outcome of any IRS contest, may have a materially adverse impact on the market for our common units and the price at which they trade. In addition, our costs of any contest with the IRS will be borne indirectly by our unitholders because the costs will reduce our cash available for distribution.

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If the IRS makes audit adjustments to our income tax returns for tax years beginning after December 31, 2017, it may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from us, in which case our cash available for distribution to our unitholders might be substantially reduced.

Pursuant to the Bipartisan Budget Act of 2015, for tax years beginning after December 31, 2017, if the IRS makes audit adjustments to our income tax returns, it may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from us. Generally, we expect to elect to have our general partner and our unitholders take such audit adjustment into account in accordance with their interests in us during the tax year under audit, but there can be no assurance that such election will be effective in all circumstances. If we are unable to have our general partner and our unitholders take such audit adjustment into account in accordance with their interests in us during the tax year under audit, our current unitholders may bear some or all of the tax liability resulting from such audit adjustment, even if such unitholders did not own units in us during the tax year under audit. If, as a result of any such audit adjustment, we are required to make payments of taxes, penalties and interest, our cash available for distribution to our unitholders might be substantially reduced.

Tax gain or loss on the disposition of our common units could be more or less than expected.

If you sell your common units, you will recognize a gain or loss for federal income tax purposes equal to the difference between the amount realized and your tax basis in those common units. Because distributions in excess of your allocable share of our net taxable income decrease your tax basis in your common units, the amount, if any, of such prior excess distributions with respect to the common units you sell will, in effect, become taxable income to you if you sell such common units at a price greater than your tax basis in those common units, even if the price you receive is less than your original cost. Furthermore, a substantial portion of the amount realized on any sale of your common units, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation and depletion recapture. In addition, because the amount realized includes a unitholder's share of our nonrecourse liabilities, if you sell your common units, you may incur a tax liability in excess of the amount of cash you receive from the sale.

Tax-exempt entities and non-U.S. persons face unique tax issues from owning our common units that may result in adverse tax consequences to them.

Investment in common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (known as IRAs), and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, is unrelated business taxable income and is taxable to them.

Distributions to non-U.S. persons are reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons are required to file federal income tax returns and pay tax on their share of our taxable income. If you are a tax-exempt entity or a non-U.S. person, you should consult a tax advisor before investing in our common units.

We treat each purchaser of common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.

Because we cannot match transferors and transferees of common units and because of other reasons, we have adopted depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to you. It also could affect the timing of these tax benefits or the amount of gain or loss from your sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to your tax returns.

We prorate our items of income, gain, loss and deduction between transferors and transferees of our common units each month based upon the ownership of our common units on the first business day of each month, instead of on the basis of the date a particular unit is transferred. The U.S. Department of Treasury and the IRS have issued Treasury Regulations that permit publicly traded partnerships to use a monthly simplifying convention that is similar to ours, but they do not specifically authorize all aspects of the proration method we have adopted. If the IRS were to successfully challenge this method, we could be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

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A unitholder whose common units are loaned to a “short seller” to effect a short sale of common units may be considered as having disposed of those common units. If so, he would no longer be treated for federal income tax purposes as a partner with respect to those common units during the period of the loan and may recognize gain or loss from the disposition.

Because a unitholder whose common units are loaned to a “short seller” to effect a short sale of common units may be considered as having disposed of the loaned common units, he may no longer be treated for federal income tax purposes as a partner with respect to those common units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deductions with respect to those common units may not be reportable by the unitholder, and any cash distributions received by the unitholder as to those common units could be fully taxable as ordinary income. Our unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to consult a tax advisor to discuss whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from loaning their common units.

We may become a resident of Canada and be required to pay tax in Canada on our worldwide income, which could reduce our earnings, and unitholders could then become taxable in Canada in respect of their ownership of our common units.

Under the Income Tax Act (Canada), or the Canadian Tax Act, a company that is resident in Canada is subject to tax in Canada on its worldwide income, and unitholders of a company resident in Canada may be subject to Canadian capital gains tax on a disposition of its units and to Canadian withholding tax on dividends paid in respect of such units.

Under Canadian law, our place of residence would generally be determined based on the location where our central management and control is exercised. Although our central management and control is currently exercised in the United States and we intend to continue to conduct our affairs and operate in such a manner, if we were nonetheless to be considered a Canadian resident for purposes of the Canadian Tax Act, our worldwide income would become subject to Canadian income tax under the Canadian Tax Act. Further, unitholders who are non-residents of Canada may become subject under the Canadian Tax Act to tax in Canada on any gains realized on the disposition of our units and would become subject to Canadian withholding tax on dividends paid or deemed to be paid by us, subject to any relief that may be available under a tax treaty or convention.

As a result of investing in our common units, you may become subject to state and local taxes and return filing requirements in jurisdictions where we operate or own or acquire properties.

In addition to federal income taxes, our unitholders could be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or control property now or in the future, even if they do not live in any of those jurisdictions. Our unitholders will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, our unitholders may be subject to penalties for failure to comply with those requirements. We currently own property or conduct business in many states, most of which impose an income tax on individuals, corporations and other entities. As we make acquisitions or expand our business, we may control assets or conduct business in additional states that impose a personal income tax. It is your responsibility to file all federal, state and local tax returns. Please consult your tax advisor.

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ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 2. PROPERTIES

Please see Item 1. Business above for descriptions and discussion of our principal properties:


•	Mineral Reserves;


•	Mines and Wet Plants;


•	Dry Plant Facilities; and


•	Transportation Logistics and Infrastructure.

In addition to these properties used in operations, we lease office space for SSS and corporate administrative staff in Fort Worth, TX.

ITEM 3. LEGAL PROCEEDINGS

Although we are, from time to time, involved in litigation and claims arising out of our operations in the normal course of business, we do not believe that we are a party to any litigation that could have a material adverse impact on our financial condition or results of operations. We are not aware of any undisclosed significant legal or governmental proceedings against us, or contemplated to be brought against us. We maintain such insurance policies with insurers in amounts and with coverage and deductibles as our general partner believes are reasonable and prudent. However, we cannot assure you that this insurance will be adequate to protect us from all material expenses related to potential future claims for personal and property damage or that these levels of insurance will be available in the future at economical prices.

Environmental Matters

On November 21, 2013, the EPA issued a General Notice Letter and Information Request (“Notice”) under Section 104(e) of CERCLA to one of our subsidiaries operating within the Fuel segment. The Notice provides that the subsidiary may have incurred liability with respect to the Reef Environmental site in Alabama, and requested certain information in accordance with Section 107(a) of CERCLA. We timely responded to the Notice. At this time, no specific claim for cost recovery has been made by the EPA (or any other potentially responsible party) against us. There is uncertainty relating to our share of environmental remediation liability, if any, because our allocable share of wastewater is unknown and the total remediation cost is also unknown. Consequently, management is unable to estimate the possible loss or range of loss, if any. We have not recorded a loss contingency accrual in our financial statements. In the opinion of management, the outcome of such matters will not have a material adverse effect on our financial position, liquidity, or results of operations.

In January 2016, AEC experienced a leak in its proprietary fuel pipeline that connects the bulk storage terminal to the transmix facility located in Birmingham, Alabama. AEC management notified the controlling governmental agencies of this condition, and commenced efforts to locate the leak, determine the cause of the leak, repair the leak, and remediate known contamination to the proximate soils and sub-grade. These efforts remain in progress, and management does not expect the costs to repair and remediate these conditions to have a material impact on our financial position, results of operations, or cash flows.

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ITEM 4. MINE SAFETY DISCLOSURES

We adhere to a strict occupational health program aimed at controlling exposure to silica dust, which includes dust sampling, a respiratory protection program, medical surveillance, training, and other components. We designed our safety program to ensure compliance with the standards of our Occupational Health and Safety Manual and U.S. Federal Mine Safety and Health Administration (“MSHA”) regulations. For both health and safety issues, extensive training is provided to employees. We have organized safety committees at our plants made up of both salaried and hourly employees. We perform internal health and safety audits and conduct tests of our abilities to respond to various situations. Our health and safety department administers the health and safety programs with the assistance of corporate personnel and plant environmental, health and safety managers.

All of our production facilities are classified as mines and are subject to regulation by MSHA under the Federal Mine Safety and Health Act of 1977 (the “Mine Act”). MSHA inspects our mines on a regular basis and issues various citations and orders when it believes a violation has occurred under the Mine Act. 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 Annual Report on Form 10-K.

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PART II

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

Our common units are listed on the NYSE under the symbol “EMES” and began trading on May 14, 2013 on a “when-issued” basis. Prior to May 14, 2013, our common units were not listed on any exchange or traded in any public market. On February 22, 2018 , the closing market price for the common units was $7.34 per unit. As of February 22, 2018 , there were 31,006,173 common units outstanding. There were 17,074 record holders of common units on December 31, 2017 . This number does not include unitholders whose units are held in trust by other entities. The actual number of unitholders is greater than the number of holders of record.

The following table sets forth, for each period indicated, the high and low sales prices per common unit, as reported on the NYSE, and the cash distributions declared and paid per common unit during each quarter for 2017 and 2016 :



Quarter Ended	High Price		Low Price		Distributions Declared Per Unit
March 31, 2016	$	6.63	$	1.97	$—
June 30, 2016	$	13.80	$	3.00	$—
September 30, 2016	$	14.60	$	8.12	$—
December 31, 2016	$	15.75	$	8.90	$—

March 31, 2017	$	24.45	$	11.11	$—
June 30, 2017	$	15.05	$	7.72	$—
September 30, 2017	$	9.90	$	5.65	$—
December 31, 2017	$	9.40	$	6.72	$—

Cash Distribution Policy

Our partnership agreement requires that we distribute all of our available cash quarterly, as defined by the Board. The actual distributions we declare are subject to our operating performance, prevailing market conditions, the impact of unforeseen events, and the approval of our Board of Directors in a manner consistent with our distribution policy. Under our Cash Distribution Policy, available cash is generally defined to mean, for each quarter, the amount of cash generated during the quarter that the Board determines is available for distribution to unitholders. The Board may consider the advice of management, the amount of cash needed for maintenance capital expenditures, debt service and other of our contractual obligations and any future operating or capital needs that the Board deems necessary or appropriate. The Board may also consider our ability to comply with the financial tests and covenants contained in our credit agreement and any other debt instrument under which we have similar obligations. The Board may establish cash reserves for the prudent conduct of our business.

As per our Credit Agreement, we were restricted from making distributions to our common unitholders. See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operation — Liquidity and Capital Resources — Credit Facility.

Issuer Purchases of Equity Securities

None.

Performance Graph

The following graph compares the performance of our common units since the IPO to the Standard & Poor's 500 Index (the “S&P 500 Index”) and the Alerian MLP Total Return Index (the “Alerian MLP Index”) by assuming $100 was invested in each investment option as of May 14, 2013, the date of the IPO, and reinvestment of all dividends and distributions. The Alerian MLP Index is a composite of the 50 most prominent energy master limited partnerships, or MLPs, and is calculated using a float-adjusted, capitalization-weighted methodology. The results shown in the graph are based on historical data and should not be considered indicative of future performance.

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Securities Authorized For Issuance Under Equity Compensation Plans

See Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters-Securities Authorized for Issuance Under Equity Compensation Plans for information regarding our equity compensation plans as of December 31, 2017 .

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ITEM 6. SELECTED FINANCIAL DATA

The following table presents our selected financial and operating data as of the dates and for the periods indicated. The following table should be read in conjunction with Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations.

Our historical results of operations for the periods presented below may not be comparable either from period to period or going forward due to the following significant transactions:


•	Our IPO in May 2013 resulted in:


•	net proceeds of $116.2 million;


•	non-recurring charges of $11.0 million;


•	our ability to repay substantially all of our pre-existing long-term debt at that time and refinance at more favorable terms; and


•	on-going general and administrative costs subsequent to our IPO related to compliance with statutory and other requirements of a publicly traded limited partnership.


•	Prior to May 14, 2013, our financial statements consist of the combined results of SSS and AEC. Subsequent to the IPO, we have also included the operations of Direct Fuels, which was purchased on May 14, 2013.


•	During 2012 and 2014, our Sand segment incurred significant growth capital expenditures to keep pace with rapidly increasing demand for our northern white frac sand.

•

Following the sale of our Fuel business in August 2016, the results of operations of the Fuel business have been classified as discontinued operations for all periods presented. We now operate our continuing business in a single sand business. We report silica sand operations as our continuing operations and fuel operations as our discontinued operations. We have revised the results of all prior periods to reflect our continuing and discontinued operations.



	Year Ended December 31,
	2017			2016			2015			2014		2013

	($ in thousands, except per unit data)
Statement of Operations Data:
Revenues	$	364,302		$	128,399		$	269,518		$	341,836	$	167,768
Operating expenses:
Cost of goods sold (excluding depreciation, depletion and amortization)	304,279			173,907			209,161			204,282		91,416
Depreciation, depletion and amortization	21,899			19,126			17,897			12,805		10,459
Selling, general and administrative expenses	26,796			20,951			27,551			32,231		20,025
Contract and project terminations	—			4,011			10,652			—		—
IPO transaction-related costs	—			—			—			—		10,966
Total operating expenses	352,974			217,995			265,261			249,318		132,866
Income (loss) from operations	11,328			(89,596		)	4,257			92,518		34,902
Other expense (income):
Interest expense, net	19,171			21,339			11,216			6,343		8,793
Loss on extinguishment of debt	—			—			—			—		907
Other expense (income)	(4,207		)	2,471			(34		)	649		(116		)
Total other expense	14,964			23,810			11,182			6,992		9,584
Income (loss) from continuing operations before provision for income taxes	(3,636		)	(113,406		)	(6,925		)	85,526		25,318
Provision (benefit) for income taxes	71			(191		)	258			205		120
Net income (loss) from continuing operations	(3,707		)	(113,215		)	(7,183		)	85,321		25,198
Discontinued Operations
Income (loss) from discontinued operations, net of taxes	(3,125		)	8,746			(2,228		)	3,758		9,972

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Gain on sale of discontinued operations	—			31,699			—			—			—
Total income (loss) from discontinued operations, net of tax	(3,125		)	40,445			(2,228		)	3,758			9,972
Net income (loss)	(6,832		)	(72,770		)	(9,411		)	89,079			35,170
Less Predecessor net income before May 14, 2013	—			—			—			—			13,124
Post-IPO net income (loss)	$	(6,832	)	$	(72,770	)	$	(9,411	)	$	89,079		$	22,046

Earnings (loss) per common unit (1)
Basic:
Earnings (loss) per common unit from continuing operations	$	(0.12	)	$	(4.55	)	$	(0.30	)	$	3.54		$	0.60
Earnings (loss) per common unit from discontinued operations	(0.11		)	1.63			(0.09		)	0.16			0.32
Basic earnings (loss) per common unit (1)	$	(0.23	)	$	(2.92	)	$	(0.39	)	$	3.70		$	0.92
Diluted:
Earnings (loss) per common unit from continuing operations	$	(0.12	)	$	(4.55	)	$	(0.30	)	$	3.54		$	0.60
Earnings (loss) per common unit from discontinued operations	(0.11		)	1.63			(0.09		)	0.16			0.32
Diluted earnings (loss) per common unit (1)	$	(0.23	)	$	(2.92	)	$	(0.39	)	$	3.70		$	0.92
Balance Sheet Data (at year end):
Property, plant and equipment, net	$	185,970		$	165,855		$	179,520		$	188,545		$	93,362
Total assets	$	308,892		$	249,904		$	420,048		$	432,127		$	319,547
Long-term debt	$	176,351		$	134,012		$	295,938		$	217,023		$	90,340
Statement of Cash Flow Data:
Net cash provided by (used in):
Operating activities	$	(2,103	)	$	(47,326	)	$	47,325		$	86,161		$	58,036
Investing activities	$	(27,667	)	$	140,541		$	(33,674	)	$	(88,172	)	$	(38,009	)
Financing activities	$	35,495		$	(114,081	)	$	343		$	6,720		$	(19,327	)
Capital expenditures:
Maintenance (2)	$	(1,540	)	$	(1,808	)	$	(2,344	)	$	(3,240	)	$	(2,394	)
Growth (3)	(5,908		)	(11,715		)	(33,130		)	(74,644		)	(18,975		)
Total	$	(7,448	)	$	(13,523	)	$	(35,474	)	$	(77,884	)	$	(21,369	)
Other Financial Data:
Cash dividends declared per common unit (4)	$	—		$	—		$	3.08		$	4.68		$	1.23
Adjusted EBITDA (5)	$	44,983		$	(37,354	)	$	50,704		$	132,827		$	86,467


(1)	Earnings per common unit are based on the results of operations subsequent to our IPO on May 14, 2013.


(2)	Maintenance capital expenditures are capital expenditures required to maintain, over the long term, our asset base, operating income or operating capacity. The maintenance capital expenditure amounts set forth above are unaudited.


(3)	Growth capital expenditures are capital expenditures made to increase, over the long term, our asset base, operating income, or operating capacity. The growth capital expenditure amounts set forth above are unaudited.


(4)	Distributions related to the earnings of one quarter are declared and paid in the subsequent quarter.


(5)	See “Adjusted EBITDA” below for a definition of Adjusted EBITDA and a reconciliation to net income (loss).

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Quarterly Data



	Quarter
	First			Second			Third			Fourth

	($ in thousands, except per unit data)
2017:
Revenues	$	75,344		$	82,602		$	103,215		$	103,141
Operating income (loss)	$	(7,501	)	$	(1,351	)	$	9,596		$	10,584
Net income (loss) from continuing operations	$	(11,390	)	$	(3,425	)	$	5,482		$	5,626
Total income (loss) from discontinued operations, net of tax	$	—		$	(2,657	)	$	(468	)	$	—
Net income (loss)	$	(11,390	)	$	(6,082	)	$	5,014		$	5,626
Basic earnings (loss) per common unit
Continuing operations	$	(0.38	)	$	(0.11	)	$	0.19		$	0.19
Discontinued operations	—			(0.09		)	(0.02		)	—
Basic earnings (loss) per common unit	$	(0.38	)	$	(0.20	)	$	0.17		$	0.19
Diluted earnings (loss) per common unit
Continuing operations	$	(0.38	)	$	(0.21	)	$	0.18		$	0.18
Discontinued operations	—			(0.09		)	(0.02		)	—
Diluted earnings (loss) per common unit	$	(0.38	)	$	(0.30	)	$	0.16		$	0.18
Cash dividends declared per common unit	$	—		$	—		$	—		$	—

2016:
Revenues	$	29,670		$	24,825		$	31,285		$	42,619
Operating income (loss)	$	(29,828	)	$	(22,868	)	$	(18,574	)	$	(18,326	)
Net income (loss) from continuing operations	$	(34,441	)	$	(28,150	)	$	(29,955	)	$	(20,669	)
Total income (loss) from discontinued operations, net of tax	$	226		$	5,253		$	35,072		$	(106	)
Net income (loss)	$	(34,215	)	$	(22,897	)	$	5,117		$	(20,775	)
Basic earnings (loss) per common unit
Continuing operations	$	(1.42	)	$	(1.17	)	$	(1.24	)	$	(0.77	)
Discontinued operations	0.01			0.22			1.45			—
Basic earnings (loss) per common unit	$	(1.41	)	$	(0.95	)	$	0.21		$	(0.77	)
Diluted earnings (loss) per common unit
Continuing operations	$	(1.42	)	$	(1.17	)	$	(1.24	)	$	(0.80	)
Discontinued operations	0.01			0.22			1.45			—
Diluted earnings (loss) per common unit	$	(1.41	)	$	(0.95	)	$	0.21		$	(0.80	)
Cash dividends declared per common unit	$	—		$	—		$	—		$	—

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ADJUSTED EBITDA

We calculate Adjusted EBITDA, a non-GAAP measure, in accordance with our Credit Agreement in effect as of December 31, 2017 as: net income (loss) plus consolidated interest expense (net of interest income), income tax expense, depreciation, depletion and amortization expense, non-cash charges and losses that are unusual or non-recurring less income tax benefits and gains that are unusual or non-recurring and other adjustments allowable under our existing credit agreement. Adjusted EBITDA is used as a supplemental financial measure by our management and external users of our financial statements, such as investors and commercial banks, to assess:


•	our debt covenant compliance. Adjusted EBITDA is a key component of critical covenants to our Credit Agreement;


•	the financial performance of our assets without regard to the impact of financing methods, capital structure or historical cost basis of our assets;


•	the viability of capital expenditure projects and the overall rates of return on alternative investment opportunities;


•	our liquidity position and the ability of our assets to generate cash sufficient to make debt payments and to make distributions; and


•	our operating performance as compared to those of other companies in our industry without regard to the impact of financing methods and capital structure.

We believe that Adjusted EBITDA provides useful information to investors because, when viewed with our GAAP results and the accompanying reconciliations, it provides a more complete understanding of our performance than GAAP results alone. We also believe that external users of our financial statements benefit from having access to the same financial measures that management uses in evaluating the results of our business.

Adjusted EBITDA should not be considered an alternative to, or more meaningful than, net income, operating income, cash flows from operating activities or any other measure of financial performance presented in accordance with GAAP. Moreover, our Adjusted EBITDA as presented may not be comparable to similarly titled measures of other companies.

Reconciliation of Net Income (Loss) and Operating Cash Flows to Adjusted EBITDA

The following tables present a reconciliation of net income (loss) to Adjusted EBITDA for each continued operations, discontinued operations and consolidated. Adjusted EBITDA for prior periods has been revised to conform to our Credit Agreement in effect as of December 31, 2017.



	Continuing			Discontinued			Consolidated

	Year Ended December 31, 2017
	($ in thousands)
Net income (loss)	$	(3,707	)	$	(3,125	)	$	(6,832	)
Interest expense, net	19,171			—			19,171
Depreciation, depletion and amortization	21,899			—			21,899
Provision for income taxes	71			—			71
EBITDA	37,434			(3,125		)	34,309
Equity-based compensation expense	1,423			—			1,423
Reduction in escrow receivable	—			3,125			3,125
Provision for doubtful accounts	17			—			17
Accretion expense	113			—			113
Retirement of assets	60			—			60
Other state and local taxes	1,896			—			1,896
Non-cash deferred lease expense	8,035			—			8,035
Unrealized (gain) loss on fair value of warrants	(4,208		)	—			(4,208		)
Other adjustments allowable under our existing credit agreement	213			—			213
Adjusted EBITDA	$	44,983		$	—		$	44,983

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	Continuing			Discontinued			Consolidated

	Year Ended December 31, 2016
	($ in thousands)
Net income (loss)	$	(113,215	)	$	40,445		$	(72,770	)
Interest expense, net	21,339			1,727			23,066
Depreciation, depletion and amortization	19,126			2,354			21,480
Provision (benefit) for income taxes	(191		)	19			(172		)
EBITDA	(72,941		)	44,545			(28,396		)
Equity-based compensation expense	388			331			719
Write-down of sand inventory	5,394			—			5,394
Contract and project terminations	4,011			—			4,011
Provision for doubtful accounts	1,684			(469		)	1,215
Accretion expense	119			—			119
Retirement of assets	559			67			626
Reduction in force	76			—			76
Other state and local taxes	1,824			296			2,120
Non-cash deferred lease expense	5,758			—			5,758
Unrealized (gain) loss on fair value of warrants	2,090			—			2,090
Non-capitalized cost of private placement	404			—			404
Gain on sale of discontinued operations, net of tax	—			(31,699		)	(31,699		)
Other adjustments allowable under our existing credit agreement	209			—			209
Adjusted EBITDA	$	(50,425	)	$	13,071		$	(37,354	)



	Continuing			Discontinued			Consolidated

	Year Ended December 31, 2015
	($ in thousands)
Net income (loss)	$	(7,183	)	$	(2,228	)	$	(9,411	)
Interest expense, net	11,216			1,338			12,554
Depreciation, depletion and amortization	17,897			10,544			28,441
Provision for income taxes	258			246			504
EBITDA	22,188			9,900			32,088
Equity-based compensation expense	2,935			597			3,532
Contract and project terminations	10,652			—			10,652
Provision for doubtful accounts	1,391			150			1,541
Accretion expense	110			—			110
Retirement of assets	138			8			146
Other state and local taxes	1,941			332			2,273
Reduction in force	362			—			362
Adjusted EBITDA	$	39,717		$	10,987		$	50,704

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	Continuing		Discontinued			Consolidated

	Year Ended December 31, 2014

	($ in thousands)
Net income (loss)	$	85,321	$	3,758		$	89,079
Interest expense, net	6,343		1,022			7,365
Depreciation, depletion and amortization	12,805		11,998			24,803
Provision for income taxes	205		433			638
EBITDA	104,674		17,211			121,885
Equity-based compensation expense	7,870		1,172			9,042
Provision for doubtful accounts	103		150			253
Accretion expense	38		—			38
Retirement of assets	19		(11		)	8
Other state and local taxes	1,224		377			1,601
Adjusted EBITDA	$	113,928	$	18,899		$	132,827



	Continuing		Discontinued			Consolidated

	Year Ended December 31, 2013
	($ in thousands)
Net income (loss)	$	25,198	$	9,972		$	35,170
Interest expense, net	8,793		1,603			10,396
Depreciation, depletion and amortization	10,459		10,369			20,828
Provision for income taxes	120		266			386
EBITDA	44,570		22,210			66,780
Equity-based compensation expense	4,982		752			5,734
IPO transaction-related costs	10,966		—			10,966
Provision for doubtful accounts	51		139			190
Accretion expense	3		—			3
Retirement of assets	773		(18		)	755
Loss (gain) on extinguishment of debt	907		—			907
Other state and local taxes	831		301			1,132
Adjusted EBITDA	$	63,083	$	23,384		$	86,467

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The following table reconciles Consolidated Adjusted EBITDA to our operating cash flows:



	Year Ended December 31,
	2017			2016			2015			2014			2013

	($ in thousands)
Adjusted EBITDA	$	44,983		$	(37,354	)	$	50,704		$	132,827		$	86,467
Interest expense, net	(15,497		)	(16,672		)	(11,729		)	(5,727		)	(6,504		)
Income tax expense	(1,967		)	(1,948		)	(2,777		)	(2,239		)	(1,518		)
Contract and project terminations - non-cash	—			(3		)	(307		)	689			(10,966		)
Reduction in force	—			(76		)	(362		)	—			—
Write-down of sand inventory	—			(5,394		)	—			—			—
Other adjustments allowable under our existing credit agreement	(213		)	(209		)	—			—			—
Cost to retire assets	19			9			—			—			—
Non-cash deferred lease expense	(8,035		)	(5,758		)	—			—			—
Change in other operating assets and liabilities	(21,393		)	20,079			11,796			(39,389		)	(9,443		)
Cash flows from operating activities:	$	(2,103	)	$	(47,326	)	$	47,325		$	86,161		$	58,036

Cash flows from investing activities:	$	(27,667	)	$	140,541		$	(33,674	)	$	(88,172	)	$	(38,009	)

Cash flows from financing activities:	$	35,495		$	(114,081	)	$	343		$	6,720		$	(19,327	)

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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion analyzes our financial condition and results of operations and should be read in conjunction with our historical consolidated financial statements and notes included elsewhere in this Annual Report.

Acquisition of Mineral Reserves

On April 12, 2017, we closed the transaction to acquire our San Antonio site for $20 million. This site is located 25 miles south of San Antonio, Texas and previously produced and sold construction, foundry and sports sands, but did not serve the energy markets. We upgraded the existing operations for conversion into frac sand production and commenced frac sand production in July 2017. As part of our expansion strategy in San Antonio, we began construction of a wet and dry plant on the site in October 2017. These plants are targeted to be operational by the second quarter of 2018. Our San Antonio reserves contain API-specification, strategic reserves (40/70 and100 mesh sands) that bolster our presence with in-basin local sands and balance our portfolio of northern white to local sands. With the close proximity of the plant to the Eagle Ford basin, we expect to sell the majority of the sand produced at the plant into this shale play, which is currently the second most active in the United States. See Note 3 to our Consolidated Financial Statements for further information.

How We Evaluate Our Operations

Our management uses a variety of financial and operational metrics to analyze our performance. We evaluate the performance of our business based on their volumes sold, revenues, operating income and Adjusted EBITDA. We view these metrics as important factors in evaluating our profitability and review these measurements frequently to analyze trends and make decisions.

Sales volumes

We view the total volume of frac sand and non-frac sand sold as an important measure of our ability to effectively utilize our assets. Higher volumes improve profitability through the spreading of fixed costs over greater volumes. Our sales volumes are subject to seasonality. Please see Part I, Item 1. Business.

Adjusted EBITDA


•	our debt covenant compliance. Adjusted EBITDA is a key component of critical covenants to our Credit Agreement.


•	the financial performance of our assets without regard to the impact of financing methods, capital structure or historical cost basis of our assets;


•	the viability of capital expenditure projects and the overall rates of return on alternative investment opportunities;


•	our liquidity position and the ability of our assets to generate cash sufficient to make debt payments and to make distributions; and


•	our operating performance as compared to those of other companies in our industry without regard to the impact of financing methods and capital structure.

See Item 6. Selected Financial and Operating Data—Adjusted EBITDA for a discussion of Adjusted EBITDA and a reconciliation to net income (loss) and operating cash flows.

Recent Trends

Beginning in late 2014, the market prices for crude oil and refined products began a steep and protracted decline which continued into 2016. This greatly impacted the demand for frac sand as drilling and completion of new oil and natural gas wells was significantly curtailed in North America. As a result, we experienced significant downward pressure on sand volume and pricing. However, commodity prices stabilized in the middle of 2016, leading to an improvement in drilling activity during the third quarter of 2016 and into 2017. Market conditions improved significantly in 2017, and based on industry outlooks from third-party research firms and customers, we expect conditions to remain strong for 2018. The increase in demand for frac sand has significantly tightened the availability of supply, and as a result, customers are seeking surety of supply through contractual commitments. We are selectively agreeing and entering into multi-year contracts with some of our key accounts. We are also evaluating take-or-pay sand supply agreements for our San Antonio operation and have already received a number of non-binding indications of interest

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for the product. We believe that sand supply agreements ensure the customers a steady supply of product in exchange for covering the infrastructure-related fixed costs plus needed margins associated with operating our business.

Although the near-term supply is closely aligned to current demand, our competitors have begun building in-basin frac sand operations targeting the Permian Basin in West Texas and the Eagle Ford basin in South Texas. There can be no assurances that all of the announced projects will be completed given permitting, construction, infrastructure, and environmental constraints. Our San Antonio operation positions us to target the second most active Texas in-basin market with comparatively less start-up costs (e.g., permitting, construction, infrastructure, and environmental analysis).

Sale of Fuel Business

In order to improve our competitive positioning and retain upside for a recovery in the oil and gas cycle, we divested our Fuel business in August 2016 to reduce our debt burden. We recorded a gain of $31.7 million on the sale of the Fuel business in 2016. Please see Note 4 to our Consolidated Financial Statements for a detailed discussion of the sale of the Fuel business.

Expansion of Sand Resources

On April 12, 2017, we closed the transaction to acquire our San Antonio operations for $20 million. The San Antonio site is located approximately 25 miles south of San Antonio, Texas and previously produced and sold construction, foundry and sports sands, but did not serve the energy markets. We upgraded the existing operations for conversion into frac sand production and commenced frac sand production in July 2017. As part of our expansion strategy in San Antonio, we began construction of a new wet and dry plant on the site in October 2017. These additional plants are targeted to be operational by the second quarter of 2018. Our San Antonio reserves contain API-specification, strategic reserves (40/70 and100 mesh sands) that bolster our presence with in-basin local sands and balance our portfolio of northern white to local sands. With the close proximity of the plant to the Eagle Ford basin, we expect to sell the majority of the sand produced at the plant into this shale play, which is currently the second most active in the United States.

Fluctuating Fixed Costs for Sand

During 2014, our rapidly expanding frac sand business required us to contract for numerous railcars to be delivered and leased in the future as well as contracting for new transload facilities. The industry downturn from 2015 through 2016 and the corresponding decline in volumes shipped created an excess number of railcars in our fleet, increasing our fixed costs per-ton. However, we successfully negotiated concessions with several of our vendors in 2016, and the significant upturn in frac sand demand has required us to place most of our idled railcars back into service, thereby reducing our fixed cost per ton.

Changing Preferences of Customer Demand

For several years leading up to 2015, most oil and gas producers preferred the highest quality, coarsest grades of frac sand (20/40 and 30/50) to complete shale wells around North America. The drop in oil and gas prices during 2015 and 2016 forced many oil and gas producers to consider alternatives for lowering the cost to complete a new well. Lower quality proppants compared to northern white sands are often located closer to the shale basins, so some operators have elected to use these proppants and save on transportation costs. Finer mesh sands (40/70 and 100 mesh) have also been used more regularly as oil and gas well completion designs have evolved. As a leading provider of frac sand, we are able to meet the changing needs of our customers and the market. Our diversified set of capabilities enables us to produce both coarse and fine grades in large quantities. With our San Antonio operation, we have two Texas in-basin plants that are well positioned geographically to meet the strong demand in the prolific Texas basins.

Cost Containment

To conserve liquidity and respond to the recent industry downturn, we became focused on prudently reducing costs while maintaining our ability to quickly respond to market demands. While we successfully implemented many cost cutting measures and achieved operational efficiencies during the downturn, we continue to negotiate price concessions and purchase commitment concessions from our major vendors, such as railcar lessors, rail transportation providers, mine operators, transload facilities operators, and professional services providers.

Sand Distribution Network

We have developed our sand distribution network over several years through the addition of third-party transload facilities in the basins in which our customers operate. We are able to charge higher prices for these terminal sales than for FOB plant sales to provide this additional service and convenience to our customers and to cover related transportation and other services costs.

Beginning in the second half of 2017 and continuing into 2018, our northern white volumes are partially constrained by railroad congestion from the class I carriers due to the high volume of shipments that have surpassed prior peak periods. We are working closely with our logistics partners to resolve the bottlenecks during this period of surging demand.

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Technology Driven Proppant Products

In early 2016, we launched our self-suspending sand marketed under the brand SandMaxX™. While subject to ongoing field testing and data validation, this new technology offers the potential to increase production in oil and gas wells in addition to improving pump time and reducing other upfront costs. Early results are proving that the technology is effective downhole, but the customer adoption rate has been slower than initially anticipated. We are still actively marketing the product and remain encouraged by the continued inquiries from existing and new customers.

We will continue to work toward transforming our Sand business from a commodity business to a more value-driven approach by developing capabilities and products that enable us to increase our presence in larger, more profitable markets.

Contract and Project Terminations

In 2014 and 2015, we began development of sand processing facilities in Independence, Wisconsin and other small projects in Ohio and Missouri. Due to a number of complications, such as an increase in projected operating costs and a decline in the market price and demand for frac sand in early 2015, we determined that these projects were no longer economically viable. In 2015, we recorded a $9.3 million charge to earnings, of which $9.2 million related to the Independence, Wisconsin facilities. This charge to earnings included items such as engineering, legal and other professional service fees, site preparation costs, and writedowns of assets to estimated net realizable value.

Management committed to a plan to discontinue these projects in April 2015. In accordance with Financial Accounting Standards Board (“FASB”) ASC 420, Exit or Disposal Cost Obligations, any contract termination charges and estimated values of continuing contractual obligations for which we will receive no future value will be recognized as a charge to earnings as of the contract termination date or cease-use date. We estimated these contract termination charges to be $1.4 million. These liabilities are reviewed periodically and may be adjusted when necessary, but we do not expect any such adjustments to be significant.

During 2016, we negotiated concessions on the majority of our railcar leases pursuant to which we cancelled or deferred deliveries of rail cars and reduced cash payments on a substantial portion of the existing rail cars in our fleet. In exchange for these concessions, we incurred a contract termination charge of $4 million. We issued at par an unsecured promissory note in the aggregate principal amount of $4 million with interest payable in cash or, in certain situations, in-kind, when certain financial metrics have been met. This note bears interest at a rate of five percent per annum and is due and payable within 30 days following the date on which financial statements are publicly available covering the first date on which these financial metrics have been met. We fully extinguished this liability and paid $4.4 million in January 2018 as part of our debt refinancing described in Note 11 to our Consolidated Financial Statements.

2018 Outlook

After two years of a prolonged energy market downturn, the North American oil and gas market exhibited a strong recovery in 2017 as energy prices rebounded significantly, prompting upstream companies to increase spending for drilling and completion activity. With oil prices currently above $60 per barrel compared to under $30 per barrel for periods of 2016, energy companies are expecting 2018 to be another year of sustained high investment. Surveys and initial public guidance for capital expenditures from North American energy companies suggest that spending could increase by 10-15% on upstream activity in 2018 compared to 2017. Under this scenario, demand for frac sand should remain strong and should translate into higher volumes consumed by the industry.

The frac sand market grew from approximately 39 million tons in 2016 to approximately 77 million tons in 2017, driven by higher rig count, more wells drilled per rig, and longer well laterals. Additionally, the amount of proppant pumped downhole per horizontal well continues to increase at a high rate as the average proppant used per well in 2017 was nearly four times the amount used 2012. Oil and gas producers are continuing to realize improved hydrocarbon production and greater financial returns with the adoption of higher frac sand loadings per well, and we expect this trend to continue in 2018 based on published industry research and discussions with customers.

Our 2017 cash flows improved from 2016 due to a dramatic increase in volume and pricing for frac sand. We also acquired our San Antonio operations in April 2017 to meet the increasing demand for locally-sourced, in-basin sand, and we expect to grow our presence in this market during 2018 through the expansion of this facility. In January 2018, we entered into refinancing transactions that strengthened our balance sheet and provided liquidity to finance our 2018 capital expenditures plan. Based on these actions and the continued strong demand for our products, we expect to have sufficient liquidity to fund our operations and planned capital expenditures in 2018. Please see “Liquidity and Capital Resources” below for more detail.

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Results of Operations

The following table summarizes our consolidated operating results for 2017 , 2016 and 2015 .



	Year Ended December 31,
	2017			2016			2015

	($ in thousands)
Revenues	$	364,302		$	128,399		$	269,518
Operating expenses:
Cost of goods sold (excluding depreciation, depletion and amortization)	304,279			173,907			209,161
Depreciation, depletion and amortization	21,899			19,126			17,897
Selling, general and administrative expenses	26,796			20,951			27,551
Contract and project terminations	—			4,011			10,652
Total operating expenses	352,974			217,995			265,261
Income (loss) from operations	11,328			(89,596		)	4,257
Other expense (income):
Interest expense, net	19,171			21,339			11,216
Other expense (income)	(4,207		)	2,471			(34		)
Total other expense	14,964			23,810			11,182
Income (loss) from continuing operations before provision for income taxes	(3,636		)	(113,406		)	(6,925		)
Provision (benefit) for income taxes	71			(191		)	258
Net income (loss) from continuing operations	(3,707		)	(113,215		)	(7,183		)
Discontinued Operations
Income (loss) from discontinued operations, net of taxes	(3,125		)	8,746			(2,228		)
Gain on sale of discontinued operations	—			31,699			—
Total income (loss) from discontinued operations, net of tax	(3,125		)	40,445			(2,228		)
Net income (loss)	$	(6,832	)	$	(72,770	)	$	(9,411	)
Adjusted EBITDA (a)	$	44,983		$	(37,354	)	$	50,704


(a)	See Item 6. Selected Financial and Operating Data—Adjusted EBITDA for a discussion of Adjusted EBITDA and a reconciliation to net income (loss).

Consolidated Summary

Our company has experienced significant change over the past three years, declining from a net loss of $9.4 million in 2015 to net loss of $72.8 million in 2016 and improving to a net loss of $6.8 million in 2017 . Most notable are the following events:


•	the market prices for crude oil and refined products began a steep and protracted decline in late 2014 which continued throughout 2015 and 2016 impacting our Sand and Fuel businesses;


•	In August 2016, we divested our Fuel business to reduce our debt burden and improve liquidity. We recorded a gain of $31.7 million on the sale of the Fuel business.


•	Commodity prices stabilized in the middle of 2016 leading to an improvement in drilling activity during the third quarter of 2016 and into 2017, thus improving performance in 2017.

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Continuing Operations



	Year Ended December 31,
	2017			2016			2015

	($ in thousands)
Revenues:
Frac sand revenues	$	359,941		$	127,873		$	268,806
Non-frac sand revenues	4,361			526			712
Total revenues	$	364,302		$	128,399		$	269,518
Operating expenses
Cost of goods sold (excluding depreciation, depletion and amortization)	304,279			173,907			209,161
Depreciation, depletion and amortization	21,899			19,126			17,897
Selling, general and administrative expenses	26,796			20,951			27,551
Contract and project terminations	—			4,011			10,652
Total operating expenses	352,974			217,995			265,261
Operating income (loss)	$	11,328		$	(89,596	)	$	4,257
Net income (loss) from continuing operations	$	(3,707	)	$	(113,215	)	$	(7,183	)
Adjusted EBITDA (a)	$	44,983		$	(50,425	)	$	39,717

Volume of frac sand sold (tons in thousands)	5,221			2,134			3,374
Volume of non-frac sand sold (tons in thousands)	312			23			18
Total volume of sand sold (tons in thousands)	5,533			2,157			3,392

Terminal sand sales (tons in thousands)	2,448			1,240			1,425

Volume of frac sand produced by dry plant (tons in thousands):
Arland, Wisconsin facility	1,800			186			1,064
Barron, Wisconsin facility	2,081			1,588			1,536
New Auburn, Wisconsin facility	1,272			352			604
Kosse, Texas facility	231			140			277
San Antonio, Texas facility (b)	50			—			—
Total volume of frac sand produced	5,434			2,266			3,481


(a)	See Item 6. Selected Financial and Operating Data—Adjusted EBITDA for a discussion of Adjusted EBITDA and a reconciliation to net income (loss).


(b)	Our San Antonio facility commenced frac sand production in July 2017.

Overview

The operating income for our sand business saw substantial decline from an operating income of $4.3 million in 2015 to an operating loss of $89.6 million in 2016 due to the steep decline in the demand and pricing of frac sand. Stabilization of commodity prices in the middle of 2016 led to an improvement in drilling activity during the third quarter of 2016 and into 2017 and thus led to a substantial improvement in operating income to $11.3 million in 2017 . During the downturn, we improved our distribution and logistics services to better serve our customers through additional transload sites. At December 31, 2017 , we had 14 transload sites in the U.S. and Canada. Many of these sites are quite distant from our processing facilities in Wisconsin. Due to the distance to these markets, we charge higher prices to recover freight and handling. This condition increases our revenues and margin, but the margin percentage at our transload sites is lower than for sand sold directly from our Wisconsin plants due to lower markups on the incremental transportation costs.

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

Revenues

Sand revenues increase d by $235.9 million primarily due to a 157% increase in total volumes sold as a result of the increased market demand for frac sand, as well as higher prices of frac sand in 2017 compared to 2016. FOB plant sales volumes increased 236% compared to a 97% increase for the higher-priced, terminal sand sales. Terminal sales as a percentage of total volumes sold decreased from 57% in 2016 to 44% in 2017. Revenue per ton increased to $65.8 in 2017 compared to $59.5 per ton in 2016 due to significant price increases.

The major changes from 2016 to 2017 are as follows:


•	$103.4 million increase in sales of northern white sand (excluding estimated transportation markups), relating primarily to a 147% increase in volumes sold as well as increased pricing in light of market conditions for frac sand;


•	an estimated $118.6 million increase for significant increases in markups per ton sold through transload sites, along with increased volumes sold through these sites;


•	$13.9 million increase in sales of native Texas sand due to increased volumes and prices at our Kosse facility and addition of our San Antonio operation in July 2017.

Cost of goods sold (excluding depreciation, depletion and amortization)

Our cost of goods sold consists primarily of direct costs such as processing plant wages, royalties, mining, purchased sand, and transportation to the plant or to transload facilities, as well as indirect costs such as plant repairs and maintenance. Our direct costs of producing sand and our logistics costs for finished product increased with our increased sales. The most significant components of the $130.4 million increase from 2016 to 2017 are:


•	The major components of the $59.9 million increase in the total cost to acquire and produce sand are:


•	Increased variable costs due to the 157% increase in total volumes sold;


•	Idling our most expensive wet plant in 2016; and


•	Allocation of fixed costs over increased volumes in 2017 impacted the cost per ton.


•	$68.9 million increase in rail transportation-related expense, primarily due to:


•	$74.9 million increased rail shipping costs due to higher volumes sold; offset by


•	$4.2 million decrease in rail lease expense; and


•	$1.8 million decrease in railcar storage costs as we placed almost all of our stored railcars back into service by year-end 2017.


•	$6.9 million increase in transload facility expenses; and


•	$5.4 million write down of sand inventory in the first quarter of 2016. This write-down was attributed to rapidly declining market conditions and a significant decline in prices. In the first quarter of 2016, we had not yet fully implemented our cost reduction strategies and we had sand inventories at higher costs.

Depreciation, depletion and amortization

Depreciation, depletion and amortization increased by $2.8 million mainly due to higher depletion expense for running all mines for a full year in 2017.

Selling, general and administrative expense

The $5.8 million increase in selling, general and administrative expense is attributable primarily to:


•	$6.0 million increase in employee-related costs due to higher staffing and bonus accruals resulting from better than expected financial results in 2017;


•	$0.7 million increase in equity-based compensation expense;


•	$0.3 million increase in employee travel related expense; offset by


•	$1.7 million decrease in bad debt expense.

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Interest expense

Net interest expense decreased $2.2 million mainly due to lower average balances on outstanding revolving credit facility borrowings, offset by the addition of the Second Lien Term Loan agreement and higher average interest rates in 2017.

Other

Other expenses decreased $6.7 million due to a non-cash mark-to-market gain of $4.2 million during the year ended December 31, 2017 , compared to a loss of $2.1 million during the year ended December 31, 2016 .

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

Revenues

Sand revenues decreased by $141.1 million, or 52%, from 2015 to 2016 primarily due to significant price decreases and a 36% decrease in total volumes sold as a result of the downturn in market demand for frac sand. Revenue per ton decreased from $79.5 in 2015 to $59.5 in 2016. However, we increased the volumes sold through transload sites from 42% to 57% of total volumes sold. We expanded our logistics and distribution network with the addition of transload facilities in the U.S. and Canada to serve our customers in various shale plays and basins. We generally charge higher prices at our transload sites in order to cover the additional costs for transportation from our plants to the transload sites.

The major changes from 2015 to 2016 are as follows:


•	$72.9 million decrease in sales of northern white sand (excluding estimated transportation markups and shortfall revenues), relating primarily to a 35% decrease in volumes sold as well as decreased pricing in light of market conditions for frac sand;


•	an estimated $46.9 million decrease in markups per ton sold through transload sites, net of increased volumes sold through these sites;


•	$7.5 million decrease in sales of native Texas sand (from our Kosse plant) due to decreased volumes;


•	$11.1 million of shortfall revenues recognized on take-or-pay customer contracts in 2015. We did not recognize any take-or-pay shortfall revenues in 2016 due to revisions to certain take-or-pay contracts; and


•	$2.6 million of business interruption insurance proceeds received in 2015 to reimburse us for lost sales during a time of equipment failure in 2014.

Cost of goods sold (excluding depreciation, depletion and amortization)

Our cost of goods sold consists primarily of direct costs such as purchased sand, transportation to the plant or to transload facilities, mining and processing costs, and plant wages as well as indirect costs such as plant repairs and maintenance. All major components of our direct costs decreased with our decreased production and with the operations of our plants. The plant maintenance and repairs did not increase significantly in 2016, as the Wisconsin plants were still quite new. The most significant components of the $35.3 million decrease from 2015 to 2016 are:


•	$26.9 million decrease in rail transportation-related expense, primarily due to:


•	$33.3 million decreased rail shipping costs due to decreased volumes sold; offset by


•	$5.2 million increase in rail lease expense;


•	$1.8 million increase in transload facility expenses; and


•	$1.2 million increase in railcar storage costs.


•	$15.5 million decrease in the total cost to acquire and produce wet and dry sand, due mainly to lower sales volumes and lower-cost sources for wet sand; offset by


•	$5.4 million write down of sand inventory in the first quarter of 2016. This write-down was attributed to the rapidly declining market conditions and a significant decline in prices. In the first quarter of 2016, we had not yet fully implemented our cost reduction strategies and we had sand inventories at higher costs; and


•	$1.8 million increase in transload facility expenses.

Depreciation, depletion and amortization

Depreciation, depletion and amortization increased by $1.2 million mainly due to a full year amortization of intangible assets added in December 2015.

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Selling, general and administrative expense

The $6.6 million decrease in selling, general and administrative expense was attributable primarily to:


•	$2.9 million decrease for employee-related costs, primarily incentive compensation due to greatly decreased profits;


•	$2.8 million decrease in equity-based compensation expense;


•	$0.3 million decrease for professional fees; and


•	$0.3 million decrease in travel related costs.

Interest expense

Net interest expense increased $10.1 million mainly due to a $3.7 million write-off of deferred debt costs due to total aggregate commitment reductions under the Credit Agreement in 2016 and higher average interest rates in 2016. As of December 31, 2016 our outstanding borrowings under the Credit Agreement bore interest at a weighted-average rate of 6.0% compared to 5.08% as of December 31, 2015.

Other

Other expenses increased $2.5 million due to a $2.1 million non-cash mark-to-market adjustment in the fair value of warrant issued in August 2016.

Discontinued Operations



	Year Ended December 31,
	2017			2016			2015

	($ in thousands)
Revenues	$	—		$	249,558		$	442,121
Cost of goods sold (excluding depreciation, depletion and amortization)	—			233,025			426,664
Depreciation and amortization	—			2,354			10,544
Selling, general and administrative expenses	—			3,687			5,568
Interest expense, net	—			1,727			1,338
Other	3,125			—			(11		)
Income (loss) from discontinued operations before provision for income taxes	(3,125		)	8,765			(1,982		)
Provision for income taxes	—			19			246
Income (loss) from discontinued operations, net of taxes	(3,125		)	8,746			(2,228		)
Gain on sale of discontinued operations	—			31,699			—
Total income (loss) from discontinued operations, net of taxes	$	(3,125	)	$	40,445		$	(2,228	)
Adjusted EBITDA (a)	$	—		$	13,071		$	10,987

Volume of refined fuels sold (gallons in thousands)	—			165,422			240,132
Volume of terminal throughput (gallons in thousands)	—			82,387			123,180
Volume of transmix refined (gallons in thousands)	—			68,326			93,128
Refined transmix as a percent of total refined fuels sold	—		%	41.3		%	38.8		%


(a)	See Item 6. Selected Financial and Operating Data—Adjusted EBITDA for a discussion of Adjusted EBITDA and a reconciliation to net income (loss).

Overview

We sold our Fuel business in August 2016, thus the results of operations of the Fuel business have been classified as discontinued operations for all periods presented.

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

We completed the sale of our Fuel business on August 31, 2016, thus we did not have any operations for the Fuel business in 2017.

During the year ended December 31, 2017 , we recorded a non-cash charge of $3.1 million for writedowns of the hydrotreator and pipeline escrow receivables relating to completion delays and cost overruns.

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

Revenues

The $192.6 million, or 44%, decrease in Fuel business revenues was attributable to a 31% decrease in total volumes sold and declines in fuel prices, generally. The decrease in volume was due to only eight months of operations in 2016, and our inability to sell 500 ppm sulfur diesel to the railroads beginning in mid-2015.

The major components of the total $192.6 million decrease in revenues were:


•	$120.1 million decrease for lower volumes of fuel sold;


•	$55.5 million decrease due to lower average fuel sales prices; and


•	$15.3 million decrease in excise and other transaction taxes. These taxes are offset on a one-to-one basis with excise and similar taxes in cost of goods sold.

Cost of goods sold (excluding depreciation, depletion and amortization)

Our cost of goods sold consists primarily of direct costs associated with the purchase of refined fuels, transmix feedstock, plant labor and burden, and costs to operate our transmix and terminal facilities.

The major components of the $193.6 million total decrease from 2015 to 2016 were:


•	$112.6 million decrease for lower volumes of fuel sold due to eight months of operations since the Fuel business was disposed on August 31, 2016;


•	$61.4 million decrease for lower average fuel purchase prices; and


•	$15.3 million decrease in excise and other transaction taxes.

Fuel business cost of goods sold include excise and similar taxes. These taxes are offset on a one-to-one basis with excise and similar taxes in revenues.

Depreciation, depletion and amortization

The $8.2 million decrease in depreciation, depletion and amortization is due primarily to the designation of the Fuel assets as held for sale as of March 31, 2016, thus no depreciation was recorded on these assets following that date.

Selling, general and administrative expense

Our selling, general and administrative expenses decreased $1.9 million, due primarily to only eight months of operations in 2016.

Liquidity and Capital Resources

Our principal liquidity requirements are to finance current operations, fund capital expenditures, finance acquisitions from time to time, service our debt and pay distributions to partners. Our sources of liquidity generally include cash generated by our operations, borrowings under our revolving credit and security agreement and issuances of equity and debt securities. We depend on the Credit Facility for both short-term and long-term capital needs and may use borrowings under our Credit Facility to fund our operations and capital expenditures to the extent cash generated by our operations is insufficient in any period. Following our entry into the New Revolving Credit Agreement and the Second Lien Note Purchase Agreement (described below), we believe that cash generated from our liquidity sources will be sufficient to meet our working capital and capital expenditure needs for at least the next 12 months.

In addition to our continued focus on generating and preserving cash from operations and maintaining availability under the Revolving Credit Facility, we may seek access to the capital markets for additional liquidity through equity and debt offerings. Any new issuances may take the form of public or private offerings for cash, equity issued to consummate acquisitions or equity issued in exchange for a portion of our outstanding debt. We may also from time to time seek to retire or purchase outstanding debt through cash purchases and/or exchanges for equity or other debt securities, in open market purchases, privately negotiated transactions or otherwise. However, there can be no assurance that we will be able to complete any of these transactions on favorable terms or at all.

In 2018, we expect to spend between $70 million and $90 million in capital expenditures to fund the expansion of our San Antonio operation and finance various capital projects that offer attractive rates of return.

Revolving Credit Facility

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PNC Bank, the “Revolving Lenders”). The New Revolving Credit Agreement replaced the Partnership’s existing $190 million senior secured revolving credit facility dated as of June 27, 2014. The New Revolving Credit Agreement provides for a $75.0 million asset-based revolving credit facility, and a $20.0 million sublimit for the issuance of letters of credit. The New Revolving Credit Agreement matures on January 5, 2022. Substantially all the Partnership’s assets are pledged as collateral on a first lien basis. This credit facility is available to (i) refinance existing indebtedness, (ii) fund fees and expenses incurred in connection with the credit facility and (iii) for general business purposes, including working capital requirements, capital expenditures, permitted acquisitions, making debt payments when due, and making distributions and dividends.

The New Revolving Credit Agreement contains various covenants and restrictive provisions and also requires the maintenance of certain financial covenants as follows:


•	a minimum liquidity requirement of $20 million at all times;


•	beginning with the fiscal quarter ending March 31, 2018, a total leverage ratio of a maximum of 5.50:1.00 decreasing quarterly thereafter to 3.00:1.00 for the fiscal quarter ending December 31, 2018 and thereafter;


•	beginning with the fiscal quarter ending March 31, 2018, a minimum fixed charge coverage ratio of 1.10:1.00; and


•	a limit on capital expenditures, subject to certain availability thresholds

Loans under the New Revolving Credit Agreement will bear interest at the Borrowers’ option at either (i) a base rate, which will be the base commercial lending rate of PNC Bank, National Association, as publicly announced to be in effect from time to time, plus an applicable margin ranging from 0.75% to 1.25% based on total leverage ratio; or (ii) LIBOR plus an applicable margin ranging from 1.75% to 2.25% based on the Partnership’s total leverage ratio.

We believe that we will be able to maintain compliance with the covenants and restrictions under the New Revolving Credit Agreement for at least the next 12 months.

Second Lien Term Loan Agreement

On January 5, 2018, we entered into a $215.0 million second lien note purchase agreement with HPS Investment Partners, LLC as notes agent and collateral agent (the “Second Lien Note Purchase Agreement”). The notes being issued under the Second Lien Note Purchase Agreement will mature on January 5, 2023. Proceeds of the sale of the notes under the Second Lien Note Purchase Agreement were used (i) to fully pay off the $40 million Partnership’s existing second lien term credit facility, (ii) to fully pay off the obligations under the Partnership’s existing revolving credit facility, (iii) to finance capital expenditures, (iv) to pay fees and expenses incurred in connection with the new second lien facility and (v) for general business purposes. Substantially all of the Partnership’s assets are pledged as collateral on a second lien basis.

The Second Lien Note Purchase Agreement contains various covenants and restrictive provisions and also requires the maintenance of certain financial covenants as follows:


•	a minimum liquidity requirement of $20 million at all times;


•	beginning with the fiscal quarter ending March 31, 2018, a total leverage ratio of a maximum of 6.00:1.00 decreasing quarterly thereafter to 3.00:1.00 for the fiscal quarter ending March 31, 2019 and thereafter;


•	beginning with the fiscal quarter ending March 31, 2018, a minimum fixed charge coverage ratio of 1.10:1.00, increasing quarterly to 2.00:1.00 for the fiscal quarter ending March 31, 2019 and thereafter; and


•	a limit on capital expenditures, subject to certain availability thresholds.

The notes under the Second Lien Note Purchase Agreement bear interest at 11.00% per annum until December 31, 2018 and ranging from 10.00% per annum to 12.00% per annum thereafter, depending on the Partnership’s leverage ratio.

Compliance

We were in compliance with all of our debt covenants at December 31, 2017 .

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Cash Flow Summary

Our cash flows include continuing and discontinued operations. We do not expect the impact of discontinued operations to be significant on our cash flows going forward.

The table below summarizes our cash flows for the years ended December 31, 2017 , 2016 and 2015 .



	Year Ended December 31,
	2017			2016			2015

	($ in thousands)
Cash flows from operating activities	$	(2,103	)	$	(47,326	)	$	47,325
Cash flows from investing activities	$	(27,667	)	$	140,541		$	(33,674	)
Cash flows from financing activities	$	35,495		$	(114,081	)	$	343
Cash and cash equivalents at beginning of period	$	4		$	20,870		$	6,876
Cash and cash equivalents at end of period	$	5,729		$	4		$	20,870

Our cash balance as of December 31, 2017 was $5.7 million compared to $4.0 thousand as of December 31, 2016 . We were subject to a cash dominion requirement as per Amendment No. 11 to our Credit Agreement, which required all cash receipts by us and our subsidiaries to be swept on a daily basis and used to reduce outstanding borrowings under the Credit Agreement. We maintained a minimal cash balance and managed our cash on a daily basis and made advances against the revolver based on our daily disbursements. Following our entry into our New Revolving Credit Agreement on January 5, 2018, we are in compliance with the requirements for excess availability and no longer in a dominion period for purposes of the agreement.

Operating Cash Flows

Cash flows from operating activities have generally trended the same as our net income (loss) adjusted for non-cash items of depreciation, depletion and amortization, equity-based compensation, amortization of deferred financing costs, contract termination costs, unrealized losses on derivative instruments, and unrealized (gain) loss on fair value of warrants. Significant changes in our working capital resulted from rapid growth of sales and billings as well as higher inventory to support our expanding business during 2017.

Investing Cash Flows

Cash flows from investing activities decreased during 2017 due to the proceeds from the sale of the Fuel business of $154.0 million in 2016, offset by the asset acquisition of our San Antonio operations in 2017 and decrease in our capital expenditures. We had significantly curtailed our capital expenditures to comply with our bank covenants that limit capital expenditures.

Cash flows from investing activities include capital expenditures for discontinued operations of $7.2 million and $7.3 million for the years ended December 31, 2016 , and 2015 .

Financing Cash Flows

The main categories of our financing cash flows can be summarized as follows:



	Year Ended December 31,
	2017			2016			2015

	($ in thousands)
Net debt proceeds (payments)	$	42,596		$	(161,363	)	$	79,160
Net proceeds from Public offering	—			36,881			—
Net proceeds from private placement	—			18,359			—
Distributions to owners	—			—			(74,351		)
Other	(7,101		)	(7,958		)	(4,466		)
Total	$	35,495		$	(114,081	)	$	343

In April 2017, we entered into a second lien term loan for $40 million. Proceeds of the term credit facility were used to (i) pay down a portion of our existing revolving credit facility, (ii) fund the acquisition described in Note 2 (iii) pay fees and expenses incurred in connection with the term credit facility and (iv) for general business purposes.

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Private Placement

On August 8, 2016, we sold an aggregate principal amount of $20 million of our Series A Preferred Units in a private placement. The net proceeds from this private placement were used to repay outstanding borrowings under our revolving credit agreement.

The first half of the Preferred Units converted into 993,049 common units on November 3, 2016, and the second half converted to 985,222 common units on February 15, 2017.

In connection with the private placement, we also issued a warrant to purchase 890,000 common units at an exercise price of $10.82 per common unit. The warrant, which expires on August 16, 2022, was exercisable immediately upon issuance and contains a cashless exercise provision and other customary provisions and protections, including anti-dilution protections. These warrants are classified as liabilities in accordance with FASB ASC 480, Distinguishing Liabilities from Equity, and are included in Other long-term liabilities on our Consolidated Balance Sheets. None of these warrants have been exercised as of December 31, 2017 .

Public Offering

In November 2016, we completed a public offering of 3,400,000 of our common units at a price of $10.00 per unit and granted the underwriters an option to purchase up to an additional 510,000 common units, which the underwriter exercised in full. The offering closed on November 23, 2016. We received proceeds (net of underwriting discounts and offering expenses) from the offering of $36.9 million . The net proceeds from this offering were used to repay outstanding borrowings under our revolving credit agreement.

Management Incentive Plans

Effective May 14, 2013, we established long-term incentive plans for our employees, directors, and consultants. These plans include the issuance of restricted and phantom units which are dilutive to common unit holders.

Contingencies

In the opinion of management, there are no contingencies that are likely to have a material adverse impact on our financial condition, liquidity or reported results.

Contractual Obligations

We have long-term contractual obligations that are required to be settled in cash. The amounts of our minimum contractual obligations as of December 31, 2017 were as follows:



	Payments Due By Period
	Total		< 1 Year		1 - 3 Years		3 - 5 Years		> 5 Years

	($ in thousands)
Long-term debt (1)	$	227,769	$	16,851	$	165,106	$	45,812	$	—
Railcar leases (2)	423,212		36,641		82,111		92,977		211,483
Unsecured notes (2)	16,607		—		—		16,607		—
Other operating leases (3)	10,488		1,095		1,717		1,647		6,029
Purchase commitments (4)	106,363		25,790		38,491		31,324		10,758
Minimum royalty payments (5)	10,429		572		1,144		1,145		7,568
Total	$	794,868	$	80,949	$	288,569	$	189,512	$	235,838

(1)

Assumes balances outstanding as of December 31, 2017 will be paid at maturity and includes interest using interest rates in effect at December 31, 2017. On January 5, 2018, we entered into a New Revolving Credit Agreement and Second Lien Note Purchase Agreement and paid the outstanding long-term debt balance in full. Complete details of this refinancing is described in Note 11 to our Consolidated Financial Statements

(2)

Includes minimum amounts payable under various operating leases for railcars as well as estimated costs to transport leased railcars from the manufacturer to our site for initial placement in service. During 2016, we completed negotiations with various railcar lessors pursuant to which we terminated a future order of railcars, deferred future railcar deliveries and reduced and deferred payments on existing leases. In exchange for these concessions, we issued at par an Unsecured Promissory Note in the aggregate principal amount of $4 million for contract termination with interest payable in cash or, in certain situations, in-kind, when certain financial metrics have been met. This note bears interest at a rate of five percent per annum and is due and payable within 30 days following the date on which financial statements are publicly available covering the first date on which certain financial metrics have been met. We also issued at par the PIK Note in the aggregate principal amount of $8 million for delivery deferrals. The

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PIK Note bears interest at a rate of 10% per annum payable in cash or, in certain situations, in-kind, when certain financial metrics have been met. The PIK Note will mature on June 2, 2020. These liabilities are included in Other long-term liabilities in our Consolidated Balance Sheets. We paid $5.4 million of this balance in January 2018 as part of our debt refinancing described in Note 11 to our Consolidated Financial Statements. We also issued warrants to purchase 370,000 common units representing limited partnership interests in the partnership in exchange of these concessions during the second quarter of 2016.


(3)	Includes lease agreements for land, facilities and equipment.


(4)	Includes minimum amounts payable under a business acquisition agreement, long-term rail transportation agreements, transload facility agreements, asset purchase/construction agreements, and other purchase commitments.


(5)	Represents minimum royalty payments for various sand mining locations. The amounts paid will differ based on amounts extracted.

Off-Balance Sheet Arrangements

As of December 31, 2017 , we had outstanding letters of credit totaling $11.2 million that support various railcar lease obligations as well as reclamation obligations for sand mining properties. We do not believe these letters of credit could have a material effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures, or capital resources.

Critical Accounting Policies and Estimates

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions. These estimates and assumptions affect the amounts reported in our Consolidated Financial Statements and notes. We base our estimates on historical experience and various other assumptions that we believe to be reasonable under the circumstances. Actual results may differ from these estimates, and estimates are subject to change due to modifications in the underlying conditions or assumptions. Currently, we do not foresee any reasonably likely changes to our current estimates and assumptions that would materially affect amounts reported in the financial statements and notes. Below are expanded discussions of our more significant accounting policies, estimates and judgments, i.e., those that reflect more significant estimates and assumptions used in the preparation of our financial statements. See Note 2 to our Consolidated Financial Statements for details about additional accounting policies and estimates made by management.

Depreciation and Depletion Methods and Estimated Useful Lives of Property, Plant and Equipment

In general, depreciation is the systematic and rational allocation of an asset's cost, less its residual value (if any), to the periods it benefits. We depreciate all of our property, plant and equipment other than mineral reserves using the straight-line method, which results in depreciation expense being incurred evenly over the life of an asset. Our estimate of depreciation expense incorporates management assumptions regarding the useful economic lives and residual values of our assets. When we place our assets in-service, we believe such assumptions are reasonable; however, circumstances may develop that would cause us to change these assumptions, which would change our depreciation amounts prospectively. Examples of such circumstances include:


•	changes in laws and regulations that limit the estimated economic life of an asset;


•	changes in technology that render an asset obsolete;


•	changes in expected salvage values; or


•	significant changes in the forecast life of proved reserves of applicable oil- and gas-producing basins, if any.

Our mineral reserves are initially recognized at cost and are depleted using the units-of-production method. Under this method, we compute the depletion expense by multiplying the number of tons of sand produced by a rate arrived at by dividing the physical units of sand produced during the period by the total estimated sand reserves volume at the beginning of the period.

Asset Retirement Obligations

We follow the provisions of FASB Accounting Standards Codification (“ASC”) 410-20, Asset Retirement Obligations, which generally applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or the normal operation of owned or leased long-lived assets.

We recognize the fair value of any liability for conditional asset retirement obligations, including environmental remediation liabilities when incurred, which is generally upon acquisition, construction or development and/or through the normal operation of our mineral reserves, if sufficient information exists to reasonably estimate the fair value of the liability. These obligations generally include the estimated net future costs of dismantling, restoring and reclaiming operating mines and related mine sites, in accordance with federal, state and local regulatory requirements. The estimated liability is based on historical industry experience in reclaiming mine sites, including estimated economic lives, external estimates as to the cost to bringing back the land to federal

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and state regulatory requirements. In calculating this estimate, we use a discount rate reflecting management's best estimate of our credit-adjusted risk-free rate.

The liability is accreted over time through periodic charges to earnings. In addition, the asset retirement cost is capitalized as part of the asset's carrying value and amortized over the life of the related asset. Reclamation costs are periodically adjusted to reflect changes in the estimated present value resulting from the passage of time and revisions to the estimates of either the timing or amount of the reclamation and abandonment costs. The reclamation obligation is based on when spending for an existing environmental disturbance is expected to occur. If the asset retirement obligation is settled for other than the carrying amount of the liability, a gain or loss will be recognized on settlement. We review, on an annual basis, unless otherwise deemed necessary, the reclamation obligation at each mine site in accordance with ASC guidance for accounting for reclamation obligations.

Impairment of Long-Lived Assets

In accordance with FASB ASC 360, long-lived assets are reviewed for impairments whenever events or changes in circumstances indicate that the related carrying amount may not be recoverable. If circumstances require a long-lived asset to be tested for possible impairment, we first compare undiscounted cash flows expected to be generated by an asset to the carrying value of the asset. If the carrying value of the long-lived asset is not recoverable on an undiscounted cash flow basis, impairment is recognized to the extent that the carrying value exceeds its fair value. Assets to be disposed of are reported at the lower of the carrying amount or fair value less selling costs. The recoverability of intangible assets subject to amortization is evaluated whenever events or changes in circumstances indicate that the carrying value of the assets may not be recoverable.

Inventory Valuation

We record the carrying value of inventory at the lower of cost or net realizable value. We base our estimates of sales value, volume and profit margin of future orders, and costs of completion and disposal on historical experience and various other assumptions that we believe to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of these assets.

Acquisitions

We use the acquisition method of accounting in accordance with FASB ASC 805, Business Combinations (“ASU 805” . Significant judgment is often required in estimating the fair values of assets acquired. For significant acquisitions, we engage a third-party valuation specialist in estimating fair values of the assets acquired.

In 2017, we acquired assets in San Antonio. Based on the analysis that we and our third-party specialist performed, we determined that substantially all of the gross fair value of the assets acquired is concentrated in a single identifiable asset, the sand reserves. Therefore, we accounted for this asset as an asset acquisition instead of a business combination under the guidance of ASC 805. We used our best estimates and assumptions to allocate the cost of the acquisition to the assets acquired on a relative fair value basis at the acquisition date. The fair value estimates are based on available historical information and on expectations and assumptions about the future production and sales volumes, market demands, the average selling price of sand and the discount factor used in estimating future cash flows. While we believe those expectations and assumptions are reasonable, they are inherently uncertain. Transaction costs incurred are expensed for business combinations and capitalized as a component of the asset costs for asset acquisitions not considered to be business combinations.

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are exposed to market risk, including the effects of adverse changes in commodity prices and interest rates as described below. We use derivative financial instruments and commodity instruments, where appropriate, to manage these risks. As a matter of policy, we do not engage in trading or speculative transactions. We also do not designate these derivatives for hedge accounting under FASB ASC 815, Derivatives and Hedging , even though these hedging transactions serve the same risk management purposes whether designated for hedge accounting treatment or not. We record the fair values of derivatives on our consolidated balance sheets, with any changes in these fair values reflected in current earnings on our consolidated statements of operations.

Commodity Price Risks

We are exposed to market risk with respect to the pricing that we receive for our sand production. Realized pricing for sand is primarily driven by a combination of take-or-pay contracts, fixed volume, and efforts-based agreements in addition to sales on the spot market. Prices under all of our supply agreements are generally fixed and are subject to adjustment, within limitations, in response to certain cost increases. However, the current market conditions have dictated that most of our pricing be determined on a spot basis. We do not enter into commodity price hedging agreements with respect to sand production.

Interest Rate Risk

We are exposed to fluctuations in interest rates charged on our variable rate debt. A hypothetical increase or decrease in interest rates by 100 basis points would have changed the interest incurred on our variable rate debt by $2.8 million for the year ended December 31, 2017 .

Customer Credit Risk

We are subject to risks of loss resulting from nonpayment or nonperformance by our customers. We examine the creditworthiness of third-party customers to whom we extend credit and manage exposure to credit risk through credit analysis, credit approval, credit limits, and monitoring procedures. For continuing operations, our top three customer balances accounted for 50% and 51% of our net accounts receivable at December 2017 and 2016 , respectively.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

EMERGE ENERGY SERVICES LP

INDEX TO FINANCIAL STATEMENTS



Emerge Energy Services LP Consolidated Financial Statements:

Report of Independent Registered Public Accounting Firm	62

Consolidated Balance Sheets as of December 31, 2017 and 2016	63

Consolidated Statements of Operations for the Years Ended December 31, 2017, 2016 and 2015	64

Consolidated Statements of Partners’ Equity for the Years Ended December 31, 2017, 2016 and 2015	65

Consolidated Statements of Cash Flows for the Years Ended December 31, 2017, 2016 and 2015	66

Notes to Consolidated Financial Statements	67

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors of Emerge Energy Services GP LLC, as General Partner of Emerge Energy Services LP and the Partners of Emerge Energy Services LP

Fort Worth, Texas

Opinion on the Consolidated Financial Statements

We have audited the accompanying consolidated balance sheets of Emerge Energy Services LP (the “Company”) as of December 31, 2017, and 2016, the related consolidated statements of operations, partners’ equity, 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 “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company and subsidiaries at December 31, 2017, and 2016, and the results of their operations and their 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.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the Company's internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control -Integrated Framework (2013)] issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) and our report dated March 1, 2018 , expressed an unqualified opinion thereon.

Basis for Opinion

These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s consolidated 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 consolidated financial statements are free of material misstatement, whether due to error or fraud.

Our audits included performing procedures to assess the risks of material misstatement of the consolidated 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 regarding the amounts and disclosures in the consolidated 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 consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ BDO USA, LLP

We have served as the Company's auditor since 2012.

Dallas, Texas

March 1, 2018

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EMERGE ENERGY SERVICES LP

CONSOLIDATED BALANCE SHEETS

($ in thousands, except unit data)



	December 31,
	2017		2016
ASSETS
Current assets:
Cash and cash equivalents	$	5,729	$	4
Trade and other receivables, net	56,951		25,103
Inventories	27,825		17,457
Prepaid expenses and other current assets	6,331		11,374
Total current assets	96,836		53,938

Property, plant and equipment, net	185,970		165,855
Intangible assets, net	1,664		4,781
Other assets, net	24,422		25,330
Total assets	$	308,892	$	249,904

LIABILITIES AND PARTNERS’ EQUITY
Current liabilities:
Accounts payable	$	18,819	$	11,221
Accrued liabilities	29,718		11,629
Total current liabilities	48,537		22,850

Long-term debt, net of current portion	176,351		134,012
Obligation for business acquisition, net of current portion	5,013		8,063
Other long-term liabilities	29,882		30,323
Total liabilities	259,783		195,248

Commitments and contingencies
Preferred units - Series A - Par value of $1,000, 0 units and 10,000 units issued and outstanding as of December 31, 2017 and December 31, 2016, respectively	—		6,914

Partners’ equity:
General partner	—		—
Limited partner common units (issued and outstanding 30,174,940 units and 29,076,456 units as of December 31, 2017 and December 31, 2016, respectively)	49,109		47,742
Total partners’ equity	49,109		47,742
Total liabilities and partners’ equity	$	308,892	$	249,904

See accompanying notes to consolidated financial statements.

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EMERGE ENERGY SERVICES LP

CONSOLIDATED STATEMENTS OF OPERATIONS

($ in thousands, except per unit data)



	Year Ended December 31,
	2017			2016			2015
Revenues	$	364,302		$	128,399		$	269,518
Operating expenses:
Cost of goods sold (excluding depreciation, depletion and amortization)	304,279			173,907			209,161
Depreciation, depletion and amortization	21,899			19,126			17,897
Selling, general and administrative expenses	26,796			20,951			27,551
Contract and project terminations	—			4,011			10,652
Total operating expenses	352,974			217,995			265,261
Income (loss) from operations	11,328			(89,596		)	4,257
Other expense (income):
Interest expense, net	19,171			21,339			11,216
Other expense (income)	(4,207		)	2,471			(34		)
Total other expense	14,964			23,810			11,182
Income (loss) from continuing operations before provision for income taxes	(3,636		)	(113,406		)	(6,925		)
Provision (benefit) for income taxes	71			(191		)	258
Net income (loss) from continuing operations	(3,707		)	(113,215		)	(7,183		)
Discontinued Operations
Income (loss) from discontinued operations, net of taxes	(3,125		)	8,746			(2,228		)
Gain on sale of discontinued operations	—			31,699			—
Total income (loss) from discontinued operations, net of tax	(3,125		)	40,445			(2,228		)
Net income (loss)	$	(6,832	)	$	(72,770	)	$	(9,411	)

Earnings (loss) per common unit (1)
Basic:
Earnings (loss) per common unit from continuing operations	$	(0.12	)	$	(4.55	)	$	(0.30	)
Earnings (loss) per common unit from discontinued operations	(0.11		)	1.63			(0.09		)
Basic earnings (loss) per common unit (1)	$	(0.23	)	$	(2.92	)	$	(0.39	)
Diluted:
Earnings (loss) per common unit from continuing operations	$	(0.12	)	$	(4.55	)	$	(0.30	)
Earnings (loss) per common unit from discontinued operations	(0.11		)	1.63			(0.09		)
Diluted earnings (loss) per common unit (1)	$	(0.23	)	$	(2.92	)	$	(0.39	)
Weighted average number of common units outstanding including participating securities (basic) (1)	30,132,480			24,870,258			23,973,850
Weighted average number of common units outstanding (diluted) (1)	30,132,480			24,870,258			23,973,850
(1) See Note 18.

See accompanying notes to consolidated financial statements.

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EMERGE ENERGY SERVICES LP

CONSOLIDATED STATEMENTS OF PARTNERS’ EQUITY

($ in thousands)



	Limited Partner Common Units			General Partner (non-economic interest)		Total Partners' Equity			Preferred Units
Balance at December 31, 2014	$	155,189		$	—	$	155,189		$	—
Net income (loss)	(9,411		)	—		(9,411		)	—
Equity-based compensation	3,654			—		3,654			—
Distributions paid	(74,337		)	—		(74,337		)	—
Distribution equivalent rights accrued	(632		)	—		(632		)	—
Recovery of short swing profit	315			—		315			—
Balance at December 31, 2015	74,778			—		74,778			—
Net income (loss)	(72,770		)	—		(72,770		)	—
Equity-based compensation	719			—		719			—
Net proceeds from issuance of preferred units	—			—		—			13,827
Conversion of preferred units	6,913					6,913			(6,913		)
Net proceeds from public offering	36,881			—		36,881			—
Other	314			—		314			—
Issuance of warrants	907			—		907			—
Balance at December 31, 2016	47,742			—		47,742			6,914
Net income (loss)	(6,832		)	—		(6,832		)	—
Equity-based compensation	1,423			—		1,423			—
Conversion of preferred units	6,914			—		6,914			(6,914		)
Other	(138		)	—		(138		)	—
Balance at December 31, 2017	$	49,109		$	—	$	49,109		$	—

See accompanying notes to consolidated financial statements.

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EMERGE ENERGY SERVICES LP

CONSOLIDATED STATEMENTS OF CASH FLOWS

($ in thousands)



	Year Ended December 31,
	2017			2016			2015
Cash flows from operating activities:
Net income (loss)	$	(6,832	)	$	(72,770	)	$	(9,411	)
Adjustments to reconcile net income (loss) to net cash flows from operating activities:
Depreciation, depletion and amortization	21,899			21,480			28,441
Equity-based compensation expense	1,423			719			3,532
Project and contract termination costs - non-cash portion	—			4,008			10,345
Unrealized (gain) loss on fair value of warrants	(4,208		)	2,090			—
Write-down of escrow receivable	3,125			—			—
Provision for doubtful accounts	17			1,215			1,541
Loss on disposal of assets	79			635			146
Amortization and write-off of deferred financing costs	3,901			6,170			1,244
Non-capitalized cost of private placement	—			404			—
Write-down of inventory	—			5,394			—
Unrealized (gain) loss on derivative instruments	(227		)	224			(419		)
Gain on sale of discontinued operations	—			(31,699		)	—
Other non-cash	113			117			110
Changes in operating assets and liabilities:
Accounts receivable	(31,865		)	(2,063		)	36,938
Inventories	(10,368		)	9,052			(10,341		)
Prepaid expenses and other current assets	1,918			2,533			(1,861		)
Accounts payable and accrued liabilities	18,014			3,916			(8,592		)
Other assets	908			1,249			(4,348		)
Cash flows from operating activities	(2,103		)	(47,326		)	47,325

Cash flows from investing activities:
Purchases of property, plant, equipment and intangible assets	(7,448		)	(13,523		)	(35,474		)
Proceeds from disposals of assets	211			82			1,787
Asset acquisition	(20,430		)	—			—
Proceeds from sale of discontinued operations, net	—			153,973			—
Collection of notes receivable	—			9			13
Cash flows from investing activities	(27,667		)	140,541			(33,674		)

Cash flows from financing activities:
Net proceeds from private placement	—			18,359			—
Net proceeds from public offering	—			36,881			—
Proceeds from line of credit borrowings	356,262			320,726			284,200
Proceeds from second lien term loan	39,597			—			—
Repayments of line of credit borrowings	(353,263		)	(482,089		)	(204,000		)
Repayments of other long-term debt	—			—			(53		)
Distributions to unitholders	—			—			(74,351		)
Payment of business acquisition obligation	(2,802		)	(848		)	(2,253		)
Payment of financing costs	(4,158		)	(6,733		)	(2,528		)
Payments on capital lease obligation	—			—			(987		)
Recovery of short swing profit	—			—			315
Other financing activities	(141		)	(377		)	—
Cash flows from financing activities	35,495			(114,081		)	343

Cash and cash equivalents:
Net increase (decrease)	5,725			(20,866		)	13,994
Balance at beginning of year	4			20,870			6,876
Balance at end of year	$	5,729		$	4		$	20,870

See accompanying notes to consolidated financial statements.

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EMERGE ENERGY SERVICES LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. ORGANIZATION AND BASIS OF PRESENTATION

Organization

Emerge Energy Services LP (“Emerge”) is a Delaware limited partnership that completed its initial public offering (“IPO”) on May 14, 2013, to become a publicly traded partnership. The combined entities of Superior Silica Sands LLC (“SSS”), a Texas limited liability company and Emerge Energy Services Operating LLC (“Emerge Operating”), a Delaware limited liability company, currently represent Emerge.

References to the “Partnership,” “we,” “our” or “us” refer collectively to Emerge and all of its subsidiaries.

We are a growth-oriented energy services company engaged in the business of mining, producing, and distributing silica sand that is a key input for the hydraulic fracturing of oil and gas wells. The Sand business conducts mining and processing operations from facilities located in Wisconsin and Texas. In addition to mining and processing silica sand for the oil and gas industry, the Sand business sells its product for use in building products and foundry operations.

We previously owned a fuel business that operated transmix processing facilities located in the Dallas-Fort Worth area and in Birmingham, Alabama. The Fuel business also offered third-party bulk motor fuel storage and terminal services, biodiesel refining, sale and distribution of wholesale motor fuels, reclamation services (which consists primarily of cleaning bulk storage tanks used by other petroleum terminal and others) and blending of renewable fuels.

We completed the sale of our Fuel business pursuant to an Amended and Restated Purchase and Sale Agreement, dated August 31, 2016 (the “Fuel Business Purchase Agreement”), with Susser Petroleum Operating Company LLC and Sunoco LP (together, “Sunoco”). Sunoco paid Emerge a purchase price of $167.7 million in cash (subject to certain working capital and other adjustments in accordance with the terms of the Fuel Business Purchase Agreement), of which $14.25 million was placed into several escrow accounts to satisfy potential claims from Sunoco for indemnification under the Fuel Business Purchase Agreement. See Note 4 to our Consolidated Financial Statements for further discussion.

The results of operations of the Fuel business have been classified as discontinued operations for all periods presented. We now operate our continuing business in a single sand segment. We report silica sand operations as our continuing operations and fuel operations as our discontinued operations.

Private Placement

On August 8, 2016, we sold an aggregate principal amount of $20 million of our Series A Preferred Units in a private placement The net proceeds from this private placement were used to repay outstanding borrowings under our revolving credit agreement.

The first half of the Preferred Units converted into 993,049 common units on November 3, 2016, and the second half converted to 985,222 common units on February 15, 2017.

In connection with the private placement, we also issued to the Purchaser a warrant to purchase 890,000 common units at an exercise price of $10.82 per common unit. The warrant, which expires on August 16, 2022, was exercisable immediately upon issuance and contains a cashless exercise provision and other customary provisions and protections, including anti-dilution protections. These warrants are classified as liabilities in accordance with FASB ASC 480, Distinguishing Liabilities from Equity, and are included in Other long-term liabilities on our Consolidated Balance Sheets. None of these warrants were exercised as of December 31, 2017 .

Public Offering

In November 2016, we completed a public offering of 3,400,000 of our common units at a price of $10.00 per unit and granted the underwriters an option to purchase up to an additional 510,000 common units, which the underwriters exercised in full. The offering closed on November 23, 2016. We received proceeds (net of underwriting discounts and offering expenses) from the offering of $36.9 million The net proceeds from this offering was used to repay outstanding borrowings under our revolving credit agreement.

Basis of Presentation and Consolidation

These consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) and include the accounts of all of our subsidiaries. All significant intercompany transactions and balances have been eliminated in consolidation.

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2. SIGNIFICANT ACCOUNTING POLICIES

Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reported period. We evaluate our estimates and assumptions on a regular basis. We base our estimates on historical experience and various other assumptions that we believe to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results could differ from those estimates, and such differences could be material.

Acquisitions

We use the acquisition method of accounting in accordance with FASB ASC 805, Business Combinations . Significant judgment is often required in estimating the fair values of assets acquired. For significant transactions, we engage a third-party valuation specialist in estimating fair values of the assets acquired. We use our best estimates and assumptions to allocate the cost of the acquisition to the assets acquired. The fair value estimates are based on available historical information and on expectations and assumptions about the future production and sales volumes, market demands, the average selling price of sand and the discount factor used in estimating future cash flows. While we believe those expectations and assumptions are reasonable, they are inherently uncertain. Transaction costs incurred are expensed for business combinations and capitalized as a component of the asset costs for asset acquisitions not considered to be business combinations.

Assets Held for Sale

We consider assets to be held for sale when management commits to a formal plan to actively market the assets for sale at a price reasonable in relation to fair value, the asset is available for immediate sale in its present condition, an active program to locate a buyer and other actions required to complete the sale have been initiated, the sale of the asset is expected to be completed within one year and it is unlikely that significant changes will be made to the plan. Upon designation as held for sale, we record the carrying value of the assets at the lower of its carrying value or its estimated fair value, less costs to sell. In accordance with generally accepted accounting principles, assets held for sale are not depreciated or amortized.

Discontinued Operations

The results of discontinued operations are presented separately, net of tax, from the results of ongoing operations for all periods presented. The expenses included in the results of discontinued operations are the direct operating expenses incurred by the discontinued segment that may be reasonably segregated from the costs of the ongoing operations of the Company. The operating results related to these lines of business have been included in discontinued operations in our Consolidated Statements of Operations for all periods presented. See Note 4 - Discontinued Operations for further detail.

Accounts Receivable and Allowance for Doubtful Accounts

Trade accounts receivable are recognized at their invoiced amounts and do not bear interest. We maintain an allowance for doubtful accounts for estimated losses resulting from the inability of our customers to make required payments. We estimate our allowances for doubtful accounts based on specifically identified amounts that are believed to be uncollectible. If the financial condition of our customers were to deteriorate, resulting in an impairment of their ability to make payments, additional allowances for doubtful accounts might be required. After all attempts to collect a receivable have failed, the receivable is written off against the allowance for doubtful accounts. Allowance for doubtful accounts was $17.0 thousand at December 31, 2017 , and $3.1 million at December 31, 2016 .

Inventories

Finished goods inventories consist of dried sand. Finished sand costs include all transportation costs necessary to transport the finished sand to the point of sale. All inventories are stated at the lower of cost or net realizable value. Raw materials inventories consist of unprocessed sand and supplies. Raw materials inventories are stated at the lower of cost or net realizable value using the average cost method. Wet sand is included in work in process. Overhead in our Sand business is capitalized at an average rate per unit based on actual costs incurred.

Property, Plant and Equipment, net

We recognize purchases of property, plant and equipment at cost, including any capitalized interest. Maintenance, repairs and renewals are expensed when incurred. Additions and significant improvements are capitalized. Disposals are removed at cost less accumulated depreciation and any gain or loss from dispositions is recognized in income.

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Depreciation of property, plant and equipment other than mineral reserves is provided for on a straight-line basis over their estimated useful lives.

Mineral reserves are initially recognized at cost, which approximates the estimated fair value as of the date of acquisition. The provision for depletion of the cost of mineral reserves is computed on the units-of-production method. Under this method, we compute the provision by multiplying the total cost of the mineral reserves by a rate arrived at dividing the physical units of sand produced during the period by the total estimated mineral resources at the beginning of the period.

Following are the estimated useful lives of our property, plant and equipment:



	Useful Lives (in Years)
Building and land improvements including assets under capital lease	10 – 39
Mineral reserves	N/A*
Railroad and related improvements	20 – 40
Machinery and equipment	5 – 10
Plant equipment including assets under capital lease	5 – 7
Industrial vehicles	3 – 7
Furniture, office equipment and software	3 – 7
Leasehold improvements	3 – 5 or lease term, whichever is less

* Depletion calculated using units-of-production method

Impairment or Disposal of Long-Lived Assets

In accordance with FASB ASC 360-10-05, Impairment or Disposal of Long-Lived Assets , long-lived assets such as property, plant and equipment, and intangible assets subject to amortization are reviewed for impairments whenever events or changes in circumstances indicate that the related carrying amount may not be recoverable. If circumstances require a long-lived asset be tested for possible impairment, we first compare undiscounted cash flows expected to be generated by an asset to the carrying value of the asset. If the carrying value of the long-lived asset is not recoverable on an undiscounted cash flow basis, impairment is recognized to the extent that the carrying value exceeds its fair value. Assets to be disposed of are reported at the lower of the carrying amount or fair value less selling costs. The recoverability of intangible assets subject to amortization is also evaluated whenever events or changes in circumstances indicate that the carrying value of the assets may not be recoverable. In management's opinion, no impairment of long-lived assets exists at December 31, 2017 and 2016 .

Intangible Assets

Intangible assets consist of trade names, patents, customer relationships, supply and transportation arrangements, and non-compete agreements. Trade names are amortized on a straight-line basis over 15 years ; patents are amortized on a straight line basis over 30 months ; customer relationships are amortized using an accelerated amortization method over 15 years ; supply and transportation arrangements are amortized using the straight-line method over varying periods up to 54 months , depending on the contract terms; and the non-compete agreements are amortized on a straight-line basis over the terms of the agreements.

Railcar Freight Costs

The cost to transport leased railcars from the manufacturer to our site for initial placement in service is capitalized and amortized over the term of the lease (typically five to seven years). The non-current portion of these capitalized costs totaled $7.2 million and $8.6 million as of December 31, 2017 and 2016 , respectively, and is included in “Other assets, net” on our Consolidated Balance Sheets.

Derivative Instruments and Hedging Activities

We account for derivatives and hedging activities in accordance with FASB ASC 815, Derivatives and Hedging , which requires entities to recognize all derivative instruments as either assets or liabilities in the balance sheet at their respective fair values. For derivative instruments that do not qualify as an accounting hedge, changes in fair value of the assets and liabilities are recognized in earnings. Our policy is to not hold or issue derivative instruments for trading or speculative purposes.

Mining and Wet Sand Processing Agreement

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support this activity. At the end of the five -year term of the agreement or following a default under the contract by the Processor, we have the right to take ownership of the wet plant and other equipment without charge. Subject to certain conditions, ownership of the plant and equipment will transfer to us at the expiration of the term. We accounted for the wet plant as a capital lease obligation.

Asset Retirement Obligations

We follow the provisions of FASB ASC 410-20, Asset Retirement Obligations, which generally applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or the normal operation of a long-lived asset. The standard requires us to recognize an estimated liability for costs associated with the future reclamation of sand mining properties, whether leased or owned, whenever we have a legal obligation to restore the site in the future.

A liability for the fair value of an asset retirement obligation with a corresponding increase to the carrying value of the related long-lived asset is recognized at the time the land is mined. The asset is depleted using the straight-line method, and the discounted liability is increased through accretion over the remaining life of the mine site.

The estimated liability is based on historical industry experience in abandoning mine sites, including estimated economic lives, external estimates as to the cost to bringing back the land to federal and state regulatory requirements. We have utilized a discounted rate reflecting management's best estimate of our credit-adjusted risk-free rate. Revisions to the liability could occur due to changes in the estimated costs, changes in the mine's economic life or if federal or state regulators enact new requirements regarding the abandonment of mine sites.

Changes in the asset retirement obligations are as follows:



	Year Ended December 31,
	2017			2016

	($ in thousands)
Beginning balance	$	2,647		$	2,570
Accretion	77			82
Reclamation costs	(8		)	(5		)
Additions	76			—
Ending balance	$	2,792		$	2,647

Revenue Recognition

Our revenue is recognized when persuasive evidence of an arrangement exists, delivery of products has occurred, the sales price charged is fixed or determinable, and collectability is reasonably assured.

We sell some of our products under short-term price agreements or at prevailing market rates. A portion of our sand business revenues are realized through take-or-pay supply agreements with large oilfield service companies. These agreements define, among other commitments, the volume of product that our customers must purchase, the volume we must provide and the price that we will charge, as well as the rate that our customers will pay. Prices under these agreements are generally fixed and subject to adjustment, upward or downward, only for certain changes in published producer cost indices or market factors. With respect to the take-or-pay arrangements, if the customer is unable to carry forward minimum quantity deficiencies, we recognize Sand segment revenues to the extent of the minimum contracted quantity, assuming payment has been received or is reasonably assured. If deficiencies can be carried forward, receipts in excess of actual sales are recognized as deferred revenues until product is actually delivered or the right to carry forward minimum quantities expires. Pursuant to the adoption of Accounting Standards Update (“ASU”) 2014-09, timing of recognizing shortfall revenues under take-or-pay contracts could change in the future.

Equity-Based Compensation and Equity Incentive Plan

We recognize expenses for equity-based compensation based on the fair value method, which requires that a fair value be assigned to a unit grant on its grant date and that this value be amortized over the grantees' required service period. Restricted and phantom units have a fair value equal to the closing market price of the common units on the date of the grant. We amortize the fair value of the restricted and phantom units over the vesting period using the straight-line method. Pursuant to the adoption of ASU 2016-09, Improvements to Employee Share-Based Payment Accounting, as of January 1, 2016, we now recognize forfeitures as they occur. For market-based awards, we make estimates as to the probability of the underlying market conditions being achieved and record expense if the conditions will probably be achieved.

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Environmental Costs

Environmental costs are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. We capitalize expenditures that extend the life of the related property or mitigate or prevent future environmental risk. We record liabilities when site restoration and environmental remediation, cleanup and other obligations are either known or considered probable and can be reasonably estimated. Such estimates require judgment with respect to costs, time frame and extent of required remedial and clean-up activities and are subject to periodic adjustments based on currently available information. At December 31, 2017 and 2016 , we had no accrued expenses related to environmental costs.

Provision for Income Taxes

For federal income tax purposes, we report our income, expenses, gains, and losses as a partnership not subject to income taxes. As such, each partner is responsible for his or her share of federal and state income tax. Net earnings for financial statement purposes may differ significantly from taxable income reportable to each partner as a result of differences between the tax basis and financial reporting basis of assets and liabilities.

We are responsible for our portion of the Texas margin tax that is included in our subsidiaries' consolidated Texas franchise tax returns.

Fair Value Measurements

Fair value is an exit price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants. Hierarchy Levels 1, 2, or 3 are terms for the priority of inputs to valuation techniques used to measure fair value. Hierarchy Level 1 inputs are quoted prices in active markets for identical assets or liabilities. Hierarchy Level 2 inputs are inputs other than quoted prices included with Level 1 that are directly or indirectly observable for the asset or liability. Hierarchy Level 3 inputs are inputs that are not observable in the market.

Our financial instruments consist primarily of cash and cash equivalents, accounts receivable, accounts payable and debt instruments. The carrying amounts of cash and cash equivalents, accounts receivable and accounts payable are representative of their fair values due to their short maturities. The carrying amounts of our revolving credit facility approximates fair value because the underlying instrument includes provisions that adjust our interest rates based on current market rates. The fair values of our other long-term liabilities are not materially different from their carrying values.

On June 2, 2016, we issued warrants to lessors to purchase 370,000 common units representing limited partnership interests in the partnership for concessions on various long-term leases. These warrants may be exercised at any time and from time to time during next five years, at an exercise price per common unit equal to $4.77 . The fair value of these warrants at issuance date was calculated at $2.45 per unit based on a Black Scholes valuation model, utilizing Level 2 inputs based on the hierarchy established in ASC 820, Fair Value Measurement. These warrants are included in Partners' Equity on our Consolidated Balance Sheets.

On August 8, 2016, we, as part of the private placement described above, also issued warrants to the Purchaser to purchase 890,000 common units at an exercise price of $10.82 per common unit. The Warrants shall be exercisable for a period of six years from the closing date and include customary provisions and protections, including anti-dilution protections. The fair value of these warrants at issuance date was calculated at $5.56 per unit based on a Black Scholes valuation model, utilizing Level 2 inputs based on the hierarchy established in ASC 820, Fair Value Measurement. This liability is marked to market each quarter with fair value gains and losses recognized immediately in earnings and included in Other income (expense) on our Consolidated Statements of Operations. We recorded a non-cash mark-to-market gain of $4.2 million during the year ended December 31, 2017 and a loss of $2.1 million during the year ended December 31, 2016 .

Concentration of Credit Risk

Financial instruments that potentially subject us to concentration of credit risk are cash and cash equivalents and trade accounts receivable. Cash deposits with banks are federally insured up to $250,000 per depositor at each financial institution; and certain of our cash balances did exceed federally insured limits as of December 31, 2017 . We maintain our cash and cash equivalents in financial institutions we consider to be of high credit quality.

We provide credit, in the normal course of business, to customers located throughout the United States and Canada. We perform ongoing credit evaluations of our customers and generally do not require collateral. In addition, we regularly evaluate our credit accounts for loss potential. The trade receivables (as a percentage of total trade receivables) as of December 31, 2017 and December 31, 2016 from such significant customers are set forth below:

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	December 31, 2017		December 31, 2016
Customer A	20	%	16	%
Customer B	17	%	13	%
Customer C	13	%	*
Customer D	*		22	%

An asterisk indicates balance is less than ten percent.

Significant Customers

The table shows the percent of revenue of our significant customers for our continuing operations for the years ended December 31, 2017 , 2016 , and 2015 .



	December 31, 2017		December 31, 2016		December 31, 2015
Customer B	18	%	*		*
Customer D	17	%	39	%	11	%
Customer C	11	%	*		13	%
Customer A	*		*		*
Customer E	*		12	%	17	%
Customer F	*		*		14	%

An asterisk indicates revenue is less than ten percent.

Segment Information

On August 31, 2016, we completed the sale of our Fuel business. Accordingly, we have discontinued segment reporting. The operating results related to these lines of business have been included in discontinued operations in our consolidated statements of operations for all periods presented.

Geographical Data

Although we own no long-term assets outside the United States, our Sand segment began selling product in Canada during 2013. We recognized $32.0 million , $15.6 million and $39.1 million of revenues in Canada for the years ended December 31, 2017 , 2016 , and 2015, respectively. All other sales have occurred in the United States.

Seasonality

For our Sand business, winter weather affects the months during which we can wash and wet-process sand in Wisconsin. Seasonality is not a significant factor in determining our ability to supply sand to our customers because we accumulate a stockpile of wet sand feedstock during non-winter months. During the winter, we process the stockpiled sand to meet customer requirements. However, we sell sand for use in oil and natural gas production basins where severe weather conditions may curtail drilling activities. This is particularly true in drilling areas located in the northern U.S. and western Canada. If severe winter weather precludes drilling activities, our frac sand sales volume may be adversely affected. Generally, severe weather episodes affect production in the first quarter with possible effect continuing into the second quarter.

Other Reclassifications

Certain reclassifications have been made to prior period amounts to conform to the current period presentation. These reclassifications do not impact net income (loss) and do not reflect a material change in the information previously presented in our consolidated financial statements.

Recent Accounting Pronouncements

In May 2014, August 2015 and May 2016, the FASB issued ASU 2014-09, Revenue from Contracts with Customers , ASU 2015-14, Revenue from Contracts with Customers, Deferral of the Effective Date , and ASU 2016-12, Revenue from Contracts with Customers, Narrow-Scope Improvements and Practical Expedients, respectively, as a new Topic, Accounting Standards Codification Topic 606. The new revenue recognition standard provides a five-step analysis of transactions to determine when and how revenue is recognized. The core principle is that a company should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. It also requires entities to disclose both quantitative and qualitative information that enable financial statements users to understand the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. This guidance is effective for annual periods beginning after December 15, 2017, and shall be applied retrospectively

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to each period presented or as a cumulative-effect adjustment as of the date of adoption. We hired an independent consultant to assist us in our assessment of our contracts. This assessment is complete and we adopted this guidance on January 1, 2018. We have concluded that this ASU does not have a significant impact on our financial position and results of operations. There will be no cumulative effect adjustment upon adoption as of January 1, 2018. Further, we do not expect a significant change to the manner or timing of recognizing revenue. We anticipate changes to our disclosures based on the requirements. We will continue to evaluate our business processes, systems and controls to ensure the accuracy and timeliness of the recognition and disclosure requirements under this guidance.

In July 2015, the FASB issued ASU 2015-11, Simplifying the Measurement of Inventory . Under this ASU, inventory will be measured at the lower of cost and net realizable value and options that currently exist for market value will be eliminated. The ASU defines net realizable value as the estimated selling prices in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation. No other changes were made to the current guidance on inventory measurement. ASU 2015-11 is effective for interim and annual periods beginning after December 15, 2016. We adopted this guidance in the first quarter of 2017 and adoption did not have a material impact on our financial position, results of operations or cash flows.

In February 2016, the FASB issued ASU 2016-02, Leases . This ASU requires lessees to recognize lease assets and lease liabilities generated by contracts longer than a year on their balance sheets. The ASU also requires companies to disclose in the footnotes to their financial statements information about the amount, timing, and uncertainty for the payments they make for the lease agreements. ASU 2016-02 is effective for public companies for annual periods and interim periods within those annual periods beginning after December 31, 2018. Early adoption is permitted for all entities. We currently have significant long-term operating leases for rail cars and transload facilities. Pursuant to the adoption, we will record substantial liabilities and corresponding assets for these leases. While we are not yet in a position to assess the full impact of the application of this ASU, we expect that the impact of recording the lease liabilities and the corresponding additional assets will have a significant impact on our financial position and results of operations and related disclosures in the notes to our consolidated financial statements.

In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows . This ASU provides classification guidance for certain cash receipts and cash payments including payment of debt extinguishment costs, settlement of zero-coupon debt instruments, insurance claim payments and distributions from equity method investees. ASU 2016-15 is effective on January 1, 2018, with early adoption permitted. We adopted this guidance on January 1, 2018 and adoption did not have a material impact on our financial position, results of operations or cash flows.

In January 2017, the FASB issued ASU 2017-01, Business Combinations . This ASU provides guidance to entities to assist with evaluating when a set of transferred assets and activities (collectively, the "set") is a business and provides a screen to determine when a set is not a business. Under this ASU, when substantially all of the fair value of gross assets acquired (or disposed of) is concentrated in a single identifiable asset, or group of similar assets, the assets acquired would not represent a business. Also, to be considered a business, an acquisition would have to include an input and a substantive process that together significantly contribute to the ability to produce outputs. We adopted this guidance in the second quarter of 2017 and applied the provisions of ASC 805 to the asset acquisition of our San Antonio operations described in Note 3 to our Consolidated Financial Statements.

3. ASSET ACQUISITION

On April 12, 2017, we closed the transaction to acquire substantially all of the assets of Materials Holding Company, Inc., Osburn Materials, Inc., Osburn Sand Co. and South Lehr, Inc. (collectively “Osburn Materials”) for $20 million . The transaction was funded with a $40 million term loan. The San Antonio site is located 25 miles south of San Antonio, Texas, and previously produced and sold construction, foundry and sports sands, but did not serve the energy markets. We upgraded the existing operations for conversion into frac sand production and commenced frac sand production in July 2017. Our San Antonio’s current sand reserves, consists mostly of 40/70 and 100 mesh sands, meets American Petroleum Institute (“API”) specifications for all grades.

We early adopted the provisions of ASC 805, Business Combinations and Accounting Standards Update (“ASU”) 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business , in accounting for this transaction. Under this guidance, if substantially all of the fair value of the gross assets acquired is concentrated in a single asset or group of similar assets, the transaction can be accounted for as an asset purchase. Based on our analysis of the transaction, substantially all of the fair value is concentrated in the sand reserves acquired, and thus we accounted for the transaction as an asset purchase.

Significant judgment is often required in estimating the fair values of assets acquired. We engaged a third-party valuation specialist in estimating fair values of the assets acquired. We used our best estimates and assumptions to allocate the cost of the acquisition to the assets acquired on a relative fair value basis at the acquisition date. The fair value estimates are based on available historical information and on expectations and assumptions about the future production and sales volumes, market demands, the average selling price of sand, and the discount factor used in estimating future cash flows. While we believe those expectations and assumptions are reasonable, they are inherently uncertain. Transaction costs of $434,000 incurred for the acquisition are capitalized as a component of the cost of the assets acquired.

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The assets acquired have been included in our consolidated balance sheet as of December 31, 2017 , and are depreciated and depleted according to the policies described in Note 2 to our Consolidated Financial Statements.

4. DISCONTINUED OPERATIONS

At March 31, 2016, the assets and liabilities of our Fuel business were classified as held for sale and the results of operations have been classified as discontinued operations for all periods presented in accordance with ASU 2014-08, "Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity."

The following corporate costs were allocated to discontinued operations for the year ended December 31, 2017 and all prior periods presented:


•	Interest on the revolver was allocated to the discontinued operations based on the allocation of debt between sand and fuel business.


•	Equity-based compensation costs recognized for the Fuel business employees were allocated to discontinued operations.


•	The taxes paid on behalf of the Fuel business were compiled by review of prior tax filings and payments. These amounts were allocated to discontinued operations.


•	General corporate overhead costs were not allocated to discontinued operations.


•	IPO transaction costs were not allocated to discontinued operations.

Summarized results of the discontinued operations for the years ended December 31, 2017 , 2016 , and 2015 are as follows:



	Year Ended December 31,

	2017			2016		2015

	($ in thousands)
Revenues (1)	$	—		$	249,558	$	442,121
Cost of goods sold (excluding depreciation, depletion and amortization) (1)	—			233,025		426,664
Depreciation and amortization	—			2,354		10,544
Selling, general and administrative expenses	—			3,687		5,568
Interest expense, net	—			1,727		1,338
Other	3,125			—		(11		)
Income (loss) from discontinued operations before provision for income taxes	(3,125		)	8,765		(1,982		)
Provision for income taxes	—			19		246
Income (loss) from discontinued operations, net of taxes	(3,125		)	8,746		(2,228		)
Gain on sale of discontinued operations	—			31,699		—
Total income (loss) from discontinued operations, net of taxes	$	(3,125	)	$	40,445	$	(2,228	)

(1) Fuel revenues and cost of goods sold include excise taxes and similar taxes:	$	—		$	35,656	$	50,939

On August 31, 2016, we completed the sale of our Fuel business pursuant to the terms of the Fuel Business Purchase Agreement. The purchase price was $167.7 million , subject to adjustment based on actual working capital conveyed at closing. The following escrow accounts were established at closing:


•	$7 million of the purchase price was withheld as a general escrow associated with certain indemnification obligations. Any unutilized escrow balance, plus any accrued interest thereon, will be paid 54 months from the closing date;


•	$4 million of the purchase price was withheld as a hydrotreater escrow to satisfy any cost overruns of the Birmingham hydrotreater completion. During the year ended December 31, 2017 , we wrote off the entire receivable relating to hydrotreator completion delays and cost overruns. This non-cash charge is included in Other expenses in our results of discontinued operations;


•	$2.25 million of the purchase price was withheld as the Renewable Fuel Standard (“RFS") escrow account. The entire amount, along with interest thereon, was collected in April 2017; and


•	$1 million of the sales purchase was withheld as a pipeline escrow account. Any unutilized escrow balance, along with any accrued interest thereon, will be released with the general escrow.

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Escrow receivables are recorded at the net present values of estimated future recoveries and will be adjusted as contingencies are resolved.

The following table represents the gain on sale from the Fuel business recognized in 2016 (in thousands). These amounts may be adjusted as certain contingencies regarding estimated transaction costs and escrow receivables are resolved in subsequent periods.



Purchase price	$	167,736
Adjustments:
Working capital true-up	3,398
Other adjustments	(2,911		)
General escrow	(7,000		)
Hydrotreater escrow	(4,000		)
Other escrow	(3,250		)
Net proceeds	153,973
Less:
Net book value of assets and liabilities sold	(125,317		)
Escrow receivable	10,597
Transaction costs including commissions	(7,679		)
Other receivables	125
Gain on sale of Fuel business	$	31,699

5. INVENTORIES

Inventories consisted of the following:



	As of December 31,
	2017		2016

	($ in thousands)
Sand work in process	$	14,650	$	7,597
Sand finished goods	12,914		9,631
Sand raw materials and supplies	261		229
Total inventory	$	27,825	$	17,457

During the first quarter of 2016, we wrote down $5.4 million of our sand inventory. This write-down was attributed to rapidly declining market conditions and a significant decline in prices. In the first quarter of 2016, we had not yet fully implemented our cost reduction strategies and we had sand raw materials and supplies inventories at higher costs.

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6. PREPAID EXPENSES AND OTHER CURRENT ASSETS

Prepaid expenses and other current assets consisted of the following:



	December 31, 2017		December 31, 2016

	($ in thousands)
Prepaid lease assets, current (1)	$	2,496	$	3,408
Prepaid transload services	1,274		768
Prepaid insurance	875		826
Escrow receivable, current	—		5,253
Other	1,686		1,119
Total	$	6,331	$	11,374


(1)	The cost to transport leased railcars from the manufacturer to our site for initial placement in service is capitalized and amortized over the term of the lease (typically five to seven years). This balance reflects the current portion of these capitalized costs.

7. PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment consisted of the following:



	As of December 31,
	2017		2016

	($ in thousands)
Machinery and equipment (1)	$	92,353	$	90,035
Buildings and improvements (1)	66,444		66,190
Land and improvements (1)	45,567		45,065
Mineral reserves	49,091		30,181
Construction in progress	15,696		2,249
Capitalized reclamation costs	2,521		2,445
Total cost	271,672		236,165
Accumulated depreciation and depletion	85,702		70,310
Net property, plant and equipment	$	185,970	$	165,855


(1)	Includes assets under capital lease

We classified $292,000 and $371,000 as assets held for sale as of December 31, 2017 and December 31, 2016 .

We recognized $18.8 million , $17.0 million , and $21.3 million of depreciation and depletion expense for the years ended December 31, 2017 , 2016 , and 2015 , respectively. Of these amounts, depreciation and depletion expense for continuing operations totaled $18.8 million , $16.0 million , and $ 17.7 million , respectively. Property, plant and equipment included as part of the assets held for sale were no longer depreciated from the time that they were classified as such.

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8. INTANGIBLE ASSETS

Our intangible assets consisted of the following at December 31, 2017 and 2016 :



	Cost		Accumulated Amortization		Net

	($ in thousands)
December 31, 2017:
Patents	$	7,443	$	6,188	$	1,255
Supply and transportation agreements	569		226		343
Non-compete agreement	100		34		66
Total	$	8,112	$	6,448	$	1,664

December 31, 2016:
Patents	$	7,443	$	3,195	$	4,248
Supply and transportation agreements	569		112		457
Non-compete agreement	100		24		76
Total	$	8,112	$	3,331	$	4,781

We recognized $3.1 million , $4.5 million , and $7.2 million of amortization expense for the years ended December 31, 2017, 2016, and 2015 , respectively. Of these amounts, amortization expense for continuing operations totaled $3.1 million , $3.1 million , and $0.2 million for the years ended December 31, 2017, 2016, and 2015 , respectively.

The following table presents the estimated future amortization expense related to intangible assets through 2022 :



Year Ending December 31,	($ in thousands)
2018	$	1,380
2019	130
2020	130
2021	16
2022	8

9. OTHER ASSETS, NET

Other assets, net consisted of the following:



	December 31, 2017		December 31, 2016

	($ in thousands)
Deferred lease asset (1)	$	8,775	$	8,826
Prepaid lease assets, net of current portion (2)	7,153		8,616
Escrow receivable - non-current (3)	5,684		5,459
Other	2,810		2,429
Total	$	24,422	$	25,330

(1)

During 2016, we completed negotiations with various railcar lessors pursuant to which we terminated future orders of railcars, deferred future railcar deliveries and reduced and deferred payments on existing leases. The cost of deferring future railcar deliveries was recorded as a deferred lease asset. This asset will be amortized over the terms of the associated leases as those railcars enter service.


(2)	The cost to transport leased railcars from the manufacturer to our site for initial placement in service is capitalized and amortized over the term of the lease (typically five to seven years). This balance reflects the non-current portion of these capitalized costs.


(3)	Non-current receivables are recorded at net present value of estimated recoveries and will be adjusted as contingencies are resolved. See Note 4 to our Consolidated Financial Statements.

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10. ACCRUED LIABILITIES

Accrued liabilities consisted of the following:



	As of December 31,
	2017		2016

	($ in thousands)
Construction	$	7,122	$	—
Salaries and other employee-related	4,633		710
Sand purchases and royalties	4,371		517
Accrued interest	2,552		641
Fuel sale related liabilities	2,475		2,784
Sales, excise, property and income taxes	1,953		136
Current portion of business acquisition obligation	1,952		1,703
Logistics	1,838		1,814
Deferred compensation	848		848
Professional fees	373		452
Current portion of contract termination	210		160
Other	1,391		1,864
Total	$	29,718	$	11,629

11. LONG-TERM DEBT

Following is a summary of our long-term debt:



	As of December 31,
	2017			2016

	($ in thousands)
Revolving credit facility - principal	$	143,700		$	140,701
Second lien term loan - principal	40,000			—
Less: Deferred financing costs, net	(7,349		)	(6,689		)
Total long-term debt	$	176,351		$	134,012

Revolving Credit Facility

On June 27, 2014, we entered into an amended and restated revolving credit and security agreement (as amended, the “Prior Credit Agreement”) among Emerge Energy Services LP, as parent guarantor, each of its subsidiaries, as borrowers (the “Borrowers”), and PNC Bank, National Association, as administrative agent and collateral agent (the “agent”), and the lenders thereto. The Prior Credit Agreement matures on June 27, 2019, and, prior to giving effect to the amendments described below, consisted of a $325 million revolving credit facility, which included a sub-limit of up to $20 million for letters of credit and incurred interest at a rate equal to either, at our option, the London Interbank Offered Rate (“LIBOR”) plus 5.00% or the base commercial lending rate of the agent, as publicly announced to be in effect from time to time, plus 4.00% . We also incurred a commitment fee of 0.375% on committed amounts that are neither used for borrowings nor under letters of credit. Substantially all of the assets of the Borrowers were pledged as collateral under the Prior Credit Agreement.

On August 31, 2016, we closed the sale of the Fuel business, used the net proceeds therefrom to repay outstanding borrowings under the prior credit facility and entered into Amendment No. 11 to the Prior Credit Agreement with the Borrowers, the lenders and the agent. Amendment No. 11, among other things, reduced commitments to $200 million , restated the Prior Credit Agreement and provided a full waiver for all defaults or events of default arising out of our failure to comply with the financial covenant to generate minimum amounts of adjusted EBITDA during the quarters ended March 31, 2016, June 30, 2016, and September 30, 2016 and the covenant to maintain the minimum amount of excess availability for any date prior to September 1, 2016.

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Pursuant to Amendment No. 11, the Prior Credit Agreement required the Partnership to maintain the following financial covenants:


•	a covenant to maintain $15 million of excess availability (as defined in the Prior Credit Agreement);


•	a covenant to limit capital expenditures (as defined in the Prior Credit Agreement) to certain maximum amounts for each quarter through March 31, 2019;


•	beginning with the quarter ending June 30, 2017, a covenant to generate consolidated EBITDA (as defined in the Prior Credit Agreement) in certain minimum amounts;


•	beginning with the quarter ending March 31, 2018, a covenant to maintain an interest coverage ratio (as defined in the Prior Credit Agreement) of not less than 2.00 to 1.00, which is scheduled to increase to 3.00 to 1.00 for the fiscal quarter ending March 31, 2019; and


•	a covenant to raise at least $ 31.2 million of net proceeds from the issuance and sale of common equity by November 30, 2016, which was satisfied by our underwritten sale of common units which closed on November 23, 2016.

In addition, the Prior Credit Agreement prohibited us from making cash distributions to our unitholders and required all cash receipts by us and our subsidiaries to be swept on a daily basis and used to reduce outstanding borrowings under the Prior Credit Agreement.

On April 12, 2017, the Partnership entered into Amendment No. 12 to the Prior Credit Agreement. The amendment permitted the Partnership and the Borrowers to enter into the Second Lien Term Loan Agreement and to reduce commitments under the Prior Credit Agreement to $190 million , and further reducing on a quarterly basis to $125 million for the quarter beginning January 1, 2019.

As a result of the reductions in the aggregate commitment, we wrote off $ 0.6 million of deferred financing costs during the year ended December 31, 2017 .

At December 31, 2017 , our outstanding borrowings under the Prior Credit Agreement bore interest at a weighted-average rate of 8.4%

On January 5, 2018, we entered into a $75.0 million Second Amended and Restated Revolving Credit and Security Agreement (the “New Revolving Credit Agreement”), among the Partnership, as parent guarantor, the Borrowers, as borrowers, PNC Bank, National Association (“PNC Bank”), as administrative agent and collateral agent, and the other lenders party thereto (together with PNC Bank, the “Revolving Lenders”). The New Revolving Credit Agreement replaced the Prior Credit Agreement. The New Revolving Credit Agreement provides for a $75.0 million asset-based revolving credit facility, and a $20.0 million sublimit for the issuance of letters of credit. The New Revolving Credit Agreement matures on January 5, 2022. Substantially all our assets are pledged as collateral on a first lien basis. This revolving credit facility is available to (i) refinance existing indebtedness, (ii) fund fees and expenses incurred in connection with the credit facility and (iii) for general business purposes, including working capital requirements, capital expenditures, permitted acquisitions, making debt payments when due, and making distributions and dividends.

The New Revolving Credit Agreement contains various covenants and restrictive provisions and also requires the maintenance of certain financial covenants as follows:


•	a minimum liquidity requirement of $20 million at all times;


•	beginning with the fiscal quarter ending March 31, 2018, a total leverage ratio of a maximum of 5.50 :1.00 decreasing quarterly thereafter to 3.00 :1.00 for the fiscal quarter ending December 31, 2018, and thereafter;


•	beginning with the fiscal quarter ending March 31, 2018, a minimum fixed charge coverage ratio of 1.10 :1.00; and


•	a limit on capital expenditures, subject to certain availability thresholds

Loans under the New Revolving Credit Agreement bore interest at the Borrowers’ option at either (i) a base rate, which will be the base commercial lending rate of PNC Bank, National Association, as publicly announced to be in effect from time to time, plus an applicable margin ranging from 0.75% to 1.25% based on total leverage ratio; or (ii) LIBOR plus an applicable margin ranging from 1.75% to 2.25% based on the Partnership’s total leverage ratio.

Second Lien Term Loan Agreement

On April 12, 2017, we entered into a $40 million second lien senior secured term loan facility with our wholly-owned subsidiaries Emerge Energy Services Operating LLC and Superior Silica Sands LLC, as borrowers (the “Borrowers”), and U.S. Bank National Association as disbursing agent and collateral agent (the “Second Lien Term Loan Agreement”). The Second Lien Term Loan Agreement matures on April 12, 2022. Proceeds of the second lien term loan facility were used to (i) pay down a portion of our revolving credit facility, (ii) fund the asset acquisition described in Note 2, (iii) pay fees and expenses incurred in connection with

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the new term credit facility and (iv) for general business purposes. Substantially all of our assets were pledged as collateral on a second lien basis under the Second Lien Term Loan Agreement.

The Second Lien Term Loan Agreement contained various covenants and restrictive provisions and also required the maintenance of certain financial covenants as follows:


•	beginning with the fiscal quarter ending March 31, 2018, an interest coverage ratio of not less than 1.70 :1.00 increasing quarterly thereafter to 2.55 :1.00 for the fiscal quarter ending March 31, 2019 and thereafter;


•	beginning with the fiscal quarter ending June 30, 2017, a minimum EBITDA of not less than $637,500 for such fiscal quarter, increasing quarterly to $50 million for the four fiscal quarter period ending June 30, 2019 and thereafter; and


•	a minimum excess availability of at least $12.75 million so long as the Prior Credit Agreement remains in effect.

Loans under the Second Lien Term Loan Agreement bear interest at the Partnership’s option at either the base rate plus 9.00% , or LIBOR plus 10.00% . At December 31, 2017 , the borrowings under the Second Lien Term Loan Agreement bore interest at a rate of 11.4% .

On January 5, 2018, we as guarantor, and the Partnership’s wholly owned subsidiaries Emerge Energy Services Operating LLC and Superior Silica Sands LLC, as issuers entered into a $215 million second lien note purchase agreement with HPS Investment Partners, LLC as notes agent and collateral agent (the “Second Lien Note Purchase Agreement”). The notes issued under the Second Lien Note Purchase Agreement will mature on January 5, 2023. Proceeds of the sale of the notes under the Second Lien Note Purchase Agreement will be used (i) to fully pay off the Partnership’s existing second lien term credit facility, (ii) to fully pay off the obligations under the Partnership’s Prior Credit Agreement, (iii) to finance capital expenditures, (iv) to pay fees and expenses incurred in connection with the new second lien facility and (v) for general business purposes. Substantially all of the Partnership’s assets are pledged as collateral on a second lien basis.

The Second Lien Note Purchase Agreement contains various covenants and restrictive provisions and also requires the maintenance of certain financial covenants as follows:


•	a minimum liquidity requirement of $20 million at all times;


•	beginning with the fiscal quarter ending March 31, 2018, a total leverage ratio of a maximum of 6.00 :1.00 decreasing quarterly thereafter to 3.00 :1.00 for the fiscal quarter ending March 31, 2019 and thereafter;


•	beginning with the fiscal quarter ending March 31, 2018, a minimum fixed charge coverage ratio of 1.10 :1.00, increasing quarterly to 2.00 :1.00 for the fiscal quarter ending March 31, 2019 and thereafter; and


•	a limit on capital expenditures, subject to certain availability thresholds.

In lieu of paying cash for certain costs, we also issued 814,295 units to the Second Lien Note holders in January 2018.

Compliance

We were in compliance with all of our debt covenants at December 31, 2017 .

12. OTHER LONG-TERM LIABILITIES

Other long-term liabilities for continuing operations consisted of the following:



	December 31, 2017		December 31, 2016
	($ in thousands)

Deferred lease obligation	$	9,561	$	5,858
Long-term promissory note	9,370		8,480
Contract and project terminations	5,348		5,319
Stock warrants	2,811		7,019
Asset retirement obligation	2,792		2,647
Other	—		1,000
Total	$	29,882	$	30,323

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Long-term Promissory Note

During the second quarter of 2016, we negotiated significant concessions on the majority of our railcar leases pursuant to which we cancelled or deferred deliveries on rail cars and reduced cash payments on a substantial portion of the existing rail cars in our fleet. In exchange of these concessions, we issued at par an Unsecured Promissory Note in the aggregate principal amount of $8 million (the “PIK Note”) for delivery deferrals. The PIK Note bears interest at a rate of 10% per annum payable in cash or, in certain situations, in-kind, when certain financial metrics have been met. The PIK Note will mature on June 2, 2020. We paid $1 million of the principal balance in January 2018 as part of our debt refinancing described in Note 11 to our Consolidated Financial Statements. We also issued warrants to purchase 370,000 common units representing limited partnership interests in the Partnership in exchange of these concessions during 2016. This note is included in Other long-term liabilities in our Consolidated Balance Sheets.

13. COMMITMENTS AND CONTINGENCIES

Contractual Obligations

The following table presents the minimum contractual obligations for contractual commitments as of December 31, 2017 .



	Railcar Leases (1)		Other Operating Leases (2)		Royalty Commitments (3)		Purchase Commitments (4)

	($ in thousands)
Year ending December 31,
2018	$	36,641	$	1,095	$	572	$	25,790
2019	39,542		861		572		19,624
2020	42,569		856		572		18,867
2021	50,769		868		572		16,250
2022	42,208		779		572		15,074
Thereafter	211,483		6,029		7,568		10,758
Total	$	423,212	$	10,488	$	10,428	106,363
Less amount representing interest							(569		)
Total less interest							$	105,794

(1)

Includes minimum amounts payable under various operating leases for railcars as well as estimated costs to transport leased railcars from the manufacturer to our site for initial placement in service. During 2016, we completed negotiations with various railcar lessors pursuant to which we terminated future order of railcars, deferred future railcar deliveries and reduced and deferred payments on existing leases. We accrued $4 million in contract termination charges and $8 million for delivery deferrals. These liabilities are included in Accrued liabilities and Other long-term liabilities in our Consolidated Balance Sheets. As part of our debt refinancing described in Note 11 to our Consolidated Financial Statements, we paid $5.4 million of these liabilities in January 2018. We also issued warrants to purchase 370,000 common units representing limited partnership interests in the partnership in exchange of these concessions.


(2)	Includes lease agreements for land, facilities and equipment.


(3)	Represents minimum royalty payments for various sand mining locations. The amounts paid will differ based on amounts extracted.


(4)	Includes minimum amounts payable under a business acquisition agreement, long-term rail transportation agreements, transload facility agreements, and other purchase commitments.

Operating Leases

We lease railcars, rail track, locomotives, office and terminal facilities, land, and equipment with various terms in connection with our daily operations. Operating lease expense for the years ended December 31, 2017 , 2016 and 2015 totaled $37.4 million , $40.7 million and $35.1 million , respectively.

Royalty Commitments

We maintain various royalty agreements related to the extraction of sand in Wisconsin, of which certain agreements require minimum payments if minimum volumes are not extracted on an annual basis.

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Purchase Commitments

We entered into several transload services agreements in 2014 with terms from five to ten years with minimum annual commitments. In May 2012, we entered into a railway shipping agreement requiring us to pay a shortfall penalty if minimum annual tonnage levels are not shipped for a term of 10 years commencing on December 1, 2012. We maintain minimum annual purchase commitments with a third-party wet sand supplier with an original term of five years. In addition, we acquired certain sand mining and processing assets in a business acquisition for which we will pay the consideration, including estimated contingent consideration, over five to seven years based on volumes of sand extracted. For the year ended December 31, 2017 , we paid $0.4 million for volume commitment shortfalls. For December 31, 2016 , we paid $1.4 million for volume commitment shortfalls at one of our transload facilities. For the year ended December 31, 2015 , we met or exceeded our minimum commitment requirements under all of our purchase agreements.

Capital Lease Obligations

In April 2014, a five -year contract with a sand processor (“Processor”) became effective to support our sand business in Wisconsin. Under this contract, the Processor financed and built a wet wash processing plant near our Wisconsin operations. As part of the agreement, the Processor wet washes our sand, creates stockpiles of washed sand and maintains the plant and equipment. During the term of the agreement the Processor will own the wet plant along with the equipment and other temporary structures used to support this activity. At the end of the five -year term of the agreement or following a default under the contract by the Processor, we have the right to take ownership of the wet plant and other equipment without charge. Subject to certain conditions, ownership of the plant and equipment will transfer to us at the expiration of the term. We accounted for the wet plant as a capital lease obligation. The original capitalized lease asset and corresponding capital lease obligation totaled $3.3 million . We extinguished this liability in 2015. However, we are still subject to minimum sand purchase obligations after the capital lease is repaid.

Other Commitments and Contingencies

Property Value Assurance (PVA)

In December 2015, we entered into an agreement to purchase certain properties and assume leases and other related agreements for future development of sand mining and processing facilities in Wisconsin. We have no plans to develop this site at this time. Under a mining agreement with a local town, we have assumed contingent obligations to indemnify owners of 32 properties for diminution of value associated with mine operations and limited moving expenses when each landowner decides to sell a property, even if no mine is yet in operation. As these contingent liabilities cannot be reasonably estimated, no liability has been recorded.

We have not accrued a liability related to the PVAs noted above as management does not believe a future payment is probable or reasonably estimable as of December 31, 2017 . We have paid $0.6 million for these guarantees to date.

Letters of Credit

As of December 31, 2017 , we had various letters of credit outstanding totaling $11.2 million . These letters of credit support various railcar lease obligations as well as reclamation obligations for sand mining properties and other vendors.

Litigation and Potentially Uninsured Liabilities

We are subject to various claims and litigation arising in the ordinary course of business. We maintain general liability insurance with limits and deductibles that management believes prudent in light of our exposure to loss and the cost of insurance. We had recognized no liabilities as of December 31, 2017 and 2016 related to uninsured claims and litigation, and current uninsured litigation matters are not expected to have a material adverse effect on our financial position, liquidity or results of operations. We expense legal costs related to claims and litigation in the period incurred.

Environmental Matters

On November 21, 2013, the EPA issued a General Notice Letter and Information Request (“Notice”) under Section 104(e) of the Comprehensive Environmental Response, Compensation, and Liability Act of 1980, as amended (“CERCLA”), to one of our subsidiaries operating within the Fuel segment. The Notice provides that the subsidiary may have incurred liability with respect to the Reef Environmental site in Alabama, and requested certain information in accordance with Section 107(a) of CERCLA. We timely responded to the Notice. At this time, no specific claim for cost recovery has been made by the EPA (or any other potentially responsible party) against us. There is uncertainty relating to our share of environmental remediation liability, if any, because our allocable share of wastewater is unknown and the total remediation cost is also unknown. Consequently, management is unable to estimate the possible loss or range of loss, if any. We have not recorded a loss contingency accrual as of December 31, 2017 and 2016 . In the opinion of management, the outcome of such matters is not expected to have a material adverse effect on our financial position, liquidity or results of operations.

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commenced efforts to locate the leak, determine the cause of the leak, repair the leak, and remediate known contamination to the proximate soils and sub-grade. These efforts remain in progress, and management does not expect the costs to repair and remediate these conditions to have a material impact on our financial position, results of operations, or cash flows.

14. CONTRACT AND PROJECT TERMINATIONS

In 2015, we revalued assets purchased for the facility in Independence, Wisconsin to their fair values of $6.2 million using Level 3 inputs and wrote off $1.7 million in December 2015.

Management committed to a plan to discontinue these projects in April 2015. In accordance with FASB ASC 420, Exit or Disposal Cost Obligations, any contract termination charges and estimated values of continuing contractual obligations for which we will receive no future value will be recognized as a charge to earnings as of the contract termination date or cease-use date. We estimated these contract termination charges to be $1.4 million . These liabilities are reviewed periodically and may be adjusted when necessary, but we do not expect any such adjustments to be significant.

During 2016, we negotiated concessions on the majority of our railcar leases pursuant to which we cancelled or deferred deliveries on rail cars and reduced cash payments on a substantial portion of the existing rail cars in our fleets. In exchange for these concessions, we incurred a contract termination charge of $4 million . We issued at par an Unsecured Promissory Note in the aggregate principal amount of $4 million with interest payable in cash or, in certain situations, in-kind, when certain financial metrics have been met. This note bears interest at a rate of 5% percent per annum and is due and payable within 30 days following the date on which financial statements are publicly available covering the first date on which these financial metrics have been met. We fully extinguished this liability and paid $4.4 million in January 2018 as part of our debt refinancing described in Note 11 to our Consolidated Financial Statements.

The following table illustrates the various contract termination liabilities and exit and disposal reserves included in Accrued liabilities and Other long-term liabilities in our Consolidated Balance Sheets:



	($ in thousands)
Balance at December 31, 2016	$	5,479
Accretion	248
Payments	(170		)
Balance at December 31, 2017	$	5,557

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15. RELATED PARTY TRANSACTIONS

Related party transactions included in our Consolidated Balance Sheets and Consolidated Statements of Operations are summarized in the following table:



	2017		2016		2015

	($ in thousands)
Balances for the year ended December 31:
Employee-related and other costs (1)	$	21,629	$	18,010	$	27,454
General and administrative expense reimbursements (2)	$	—	$	—	$	280
Lease expense	$	—	$	17	$	25

Balances as of December 31:
Accounts receivable, net	$	962	$	371	$	295
Accounts payable and accrued liabilities	$	800	$	436	$	553


(1)	We do not have any employees. Our general partner manages our human resource assets, including fringe benefits, other employee-related charges, and other costs. We routinely and regularly reimburse our general partner for any employee-related and other costs paid on our behalf, and report such costs as operating expenses.


(2)	We paid $40,000 to one of our independent directors for production of a video clip for investors and press in 2015.

Agreements with Affiliates

Registration Rights Agreement. In connection with closing of the IPO, we entered into a Registration Rights Agreement, dated as of May 14, 2013 (the “Registration Rights Agreement”), by and between AEC Resources LLC, Ted W. Beneski, Superior Silica Resources LLC, Kayne Anderson Development Company and LBC Sub V, LLC. Pursuant to the Registration Rights Agreement, we agreed to register for resale the restricted common units of the Partnership (the “Restricted Units”) issued to the other parties to the Registration Rights Agreement. We also agreed, subject to certain limitations, to allow the holders to sell Restricted Units in connection with certain registered offerings that we may conduct in the future and to provide holders of a specified number of Restricted Units the right to demand that we conduct an underwritten public offering of Restricted Units under certain circumstances. The Registration Rights Agreement contains representations, warranties, covenants and indemnities that are customary for private placements by public companies.

Services Agreement. On May 14, 2013, in connection with the closing of the IPO, we entered into an administrative services agreement with Insight Equity, pursuant to which Insight Equity provides specific general and administrative services to us. Under this agreement, we reimburse Insight Equity based on agreed upon formulas for actual travel and other expenses on our behalf. In addition, an executive employee of Insight Equity was the head of the Fuel business. We paid this executive for services rendered to the Fuel business and recorded these costs as a charge to earnings. After the sale of the fuel business, the executive employee became an Emerge Energy Services, GP, LLC employee. The administrative services agreement will remain in force until (i) the date we and Insight Equity mutually agree to terminate it; (ii) the final distribution in liquidation of the Partnership or our subsidiaries; or (iii) the date on which either Insight Equity or its affiliates collectively controls less than 51% of equity of our general partner.

16. EQUITY-BASED COMPENSATION

Effective May 14, 2013, we adopted our 2013 Long-Term Incentive Plan (the “LTIP”) for providing long-term incentives for employees, directors, and consultants who provide services to us, and provides for the issuance of an aggregate of up to 2,321,968 common units to be granted either as options, restricted units, phantom units, distribution equivalent rights, unit appreciation rights, unit award, profits interest units, or other unit-based award granted under the plan. All of our outstanding grants will be settled through issuance of limited partner common units.

For remaining phantom units granted to employees in 2013, we currently assume a 60 -month vesting period, which represents management’s estimate of the amount of time until all vesting conditions have been met. For other phantom units granted to employees, we have a 24 to 36 -month vesting period. Restricted units are awarded to our independent directors on each anniversary of our IPO, each with a vesting period of one year. Regarding distributions for independent directors and other employees, distributions are credited to a distribution equivalent rights account for the benefit of each participant and become payable generally within 45 days following the date of vesting. As of December 31, 2017 , the unpaid liability for distribution equivalent rights totaled $0.8 million .

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In 2017 , we granted 162,139 time based phantom units to certain officers and other employees to vest in equal installments on each anniversary date of the grant over a period of two to three years.

The following table summarizes awards granted during the year ended December 31, 2017 .



	Total Units		Phantom Units		Restricted Units		Fair Value per Unit at Award Date
Outstanding at December 31, 2016	289,607		213,851		75,756		$	13.09
Granted	185,180		162,139		23,041		$	9.35
Vested	(128,966	)	(53,210	)	(75,756	)	$	12.77
Forfeitures	(12,000	)	(12,000	)	—		$	—
Outstanding at December 31, 2017	333,821		310,780		23,041		$	13.10

For the years ended December 31, 2017 , 2016 , and 2015 , we recorded non-cash compensation expense relating to equity-based compensation of $1.4 million , $0.7 million , and $3.5 million , respectively, in selling, general and administrative expenses. Non-cash equity-based compensation expense for continuing operations was $1.4 million , $0.4 million , and $2.9 million for the years ended December 31, 2017 , 2016 , and 2015 , respectively.

As of December 31, 2017 , the unrecognized compensation expense related to the grants discussed above amounted to $1.7 million to be recognized over a weighted average of 1.02 years.

17. INCOME TAXES

Continuing operations

Our provision for income taxes for continuing operations relates to: (i) Texas margin taxes for the Partnership, and (ii) an insignificant amount of Canadian income taxes on SSS earnings in Canada (most of our earnings are exempted under a U.S/Canada tax treaty). For federal income tax purposes, we report our income, expenses, gains, and losses as a partnership not subject to income taxes. As such, each partner is responsible for his or her share of federal and state income tax. Net earnings for financial statement purposes may differ significantly from taxable income reportable to each partner because of differences between the tax basis and financial reporting basis of assets and liabilities.

The composition of our provision for income taxes for continuing operations is as follows:



	Year Ended December 31,
	2017			2016			2015

	($ in thousands)
Texas margin tax	$	85		$	(192	)	$	273
Canadian income tax	(14		)	1			(15		)
Total provision for income taxes	$	71		$	(191	)	$	258

We are responsible for our portion of the Texas margin tax that is included in our subsidiaries’ consolidated Texas franchise tax returns. For our operations in Texas, the margin tax rate is 0.38% as defined by applicable state law. The margin tax qualifies as an income tax under GAAP, which requires us to recognize the impact of this tax on the temporary differences between the financial statement assets and liabilities and their tax basis attributable to such tax.

Discontinued operations

Our provision for income taxes for discontinued operations relates to (i) Texas margin taxes for Direct Fuels, and (ii) federal and state income taxes for Emerge Energy Distributors Inc. (“Distributor”). Distributor reports its income, expenses, gains, and losses as a corporation and is subject to both federal and state income taxes. Federal and state income tax expense and Texas margin tax expense for discontinued operations for the years ended December 31, 2016 and 2015 was $19 thousand and $231 thousand .

18. EARNINGS PER COMMON UNIT

We compute basic earnings (loss) per unit by dividing net income (loss) by the weighted-average number of common units outstanding including certain participating securities. Participating securities include unvested equity-based payment awards that contain rights to distributions, as well as convertible preferred units and warrants that contain contractual rights to participate in any distributions that are declared. It is our policy to exclude participating securities, convertible preferred units and warrants

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from the calculation of basic earnings (loss) per unit in periods of net losses from continuing operations since these securities are not contractually obligated to share in losses.

Diluted earnings per unit is computed by dividing net income by the weighted-average number of common units outstanding, including the number of common units that would have been outstanding had potential dilutive units been exercised. The dilutive effect of restricted units is reflected in diluted net income per unit by applying the treasury stock method. For periods in which warrants are dilutive, we reverse the income effects of the warrants and include incremental units in our computation of diluted earnings per unit. Under FASB ASC 260-10-45, Contingently Issuable Shares, 93,806 of our outstanding phantom units are not included in basic or diluted earnings per common unit calculations as of December 31, 2017 .

Basic and diluted earnings per unit are computed as follows:



	Year ended December 31,
	2017			2016			2015

	($ in thousands except per unit data)
Net income (loss) from continuing operations	$	(3,707	)	$	(113,215	)	$	(7,183	)
Net income (loss) from discontinued operations	(3,125		)	40,445			(2,228		)
Net Income (loss)	$	(6,832	)	$	(72,770	)	$	(9,411	)

Weighted average common units outstanding	30,132,480			24,870,258			23,973,850
Weighted average units deemed participating securities	—			—			—
Weighted average number of common units outstanding including participating securities (basic)	30,132,480			24,870,258			23,973,850
Weighted average potentially dilutive units outstanding	—			—			—
Weighted average number of common units outstanding (diluted)	30,132,480			24,870,258			23,973,850

Basic earnings (loss) per unit:
Earnings (loss) per common unit from continuing operations	$	(0.12	)	$	(4.55	)	$	(0.30	)
Earnings (loss) per common unit from discontinued operations	(0.11		)	1.63			(0.09		)
Basic earnings (loss) per common unit	$	(0.23	)	$	(2.92	)	$	(0.39	)

Diluted earnings (loss) per unit:
Earnings (loss) per common unit from continuing operations	$	(0.12	)	$	(4.55	)	$	(0.30	)
Earnings (loss) per common unit from discontinued operations	(0.11		)	1.63			(0.09		)
Diluted earnings (loss) per common unit	$	(0.23	)	$	(2.92	)	$	(0.39	)

19. RECURRING FAIR VALUE MEASUREMENTS

We follow FASB ASC 820, Fair Value Measurement , which defines fair value, establishes a framework for measuring fair value, and specifies disclosures about fair value measurements. This guidance establishes a hierarchy for disclosure of the inputs to valuations used to measure fair value. The hierarchy prioritizes the inputs into three broad levels as follows.


•	Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities.


•	Level 2 inputs are quoted prices for similar assets and liabilities in active markets or inputs that are observable for the asset or liability, either directly or indirectly through market corroboration, for substantially the full term of the financial instrument.


•	Level 3 inputs are measured based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable from objective sources.

Our valuation models consider various inputs including (a) mark to market valuations, (b) time value and, (c) credit worthiness of valuation of the underlying measurement.

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A financial asset or liability’s classification within the hierarchy is determined based on the lowest level of input that is significant to the fair value measurement.

The following table shows the zero interest rate swap agreements we entered into during 2013 to manage interest rate risk associated with our variable rate borrowings. The rate swaps matured October 16, 2017.



Agreement Date	Effective Date	Maturity Date	Notional Amount	Fixed Rate	Variable Rate
Nov. 1, 2013	Oct. 14, 2014	Oct. 16, 2017	$25,000,000	1.33200%	1 Month LIBOR
Nov. 7, 2013	Oct. 14, 2014	Oct. 16, 2017	$25,000,000	1.25500%	1 Month LIBOR
Nov. 21, 2013	Oct. 14, 2014	Oct. 16, 2017	$20,000,000	1.21875%	1 Month LIBOR

We do not designate our derivative instruments as hedges under GAAP. As a result, we recognize derivatives at fair value on the consolidated balance sheet with resulting gains and losses reflected in interest expense (for interest rate swap agreements) and cost of goods sold (for derivative commodity instruments), as reported in the consolidated statements of operations. Our derivative instruments serve the same risk management purpose whether designated as a hedge or not. We derive fair values from published market interest rates and fuel price quotes (Level 2 inputs). The precise level of open position commodity derivatives is dependent on inventory levels, expected inventory purchase patterns, and market price trends. We do not use derivative financial instruments for trading or speculative purposes.

On August 8, 2016, we, as part of the private placement described above, also issued warrants to purchase 890,000 common units at an exercise price of $10.82 per common unit. The warrants are exercisable for a period of six years from the closing date and include customary provisions and protections, including anti-dilution protections. The fair value of these warrants at issuance date was calculated at $5.56 per unit based on a Black Scholes valuation model, utilizing Level 2 inputs based on the hierarchy established in ASC 820, Fair Value Measurement. This liability is marked to market each quarter with fair value gains and losses recognized immediately in earnings and included in Other income (expense) on our Consolidated Statements of Operations. We recorded a non-cash mark-to-market gain of $4.2 million during the year ended December 31, 2017 and a loss of $2.1 million during the year ended December 31, 2016 .

The fair values of outstanding derivative instruments and warrants and their classifications within our Consolidated Balance Sheets are summarized as follows:



	December 31, 2017		December 31, 2016		Classification

	($ in thousands)
Interest rate swaps	$	—	$	227	Accrued liabilities
Warrant liability	$	2,811	$	7,019	Other long-term liabilities

The effect of derivative instruments, none of which has been designated for hedge accounting, on our Consolidated Statements of Operations was as follows:



	Year Ended December 31,
	2017		2016			2015			Classification

	(income (expense), $ in thousands)
Interest rate swaps	$	61	$	(334	)	$	(820	)	Interest expense, net
Commodity derivative contracts	—		(557		)	715			Income from discontinued operations
Warrants	4,208		(2,090		)	$	—		Other (expense) income
	$	4,269	$	(2,981	)	$	(105	)

20. RETIREMENT PLAN

We sponsor a 401(k) plan for substantially all employees that provides for us to match 100% of participant contributions for a maximum of 5% of the participant’s pay. Additionally, we can make discretionary contributions as deemed appropriate by management.

As of May 1, 2017, we reestablished the employer 401(k) contributions, which was previously suspended on July 1, 2016. Our employer contributions totaled $0.4 million , $0.3 million , and $0.8 million for the years ended December 31, 2017 , 2016 , and 2015 , respectively. We classified $118 thousand and $275 thousand to income (loss) from discontinued operations, net of taxes for the twelve months ended December 31, 2016 , and 2015 , respectively.

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21. SUPPLEMENTAL CASH FLOW DISCLOSURES

The following supplemental disclosures may assist in the understanding of our Consolidated Statements of Cash Flows:



	Year Ended December 31,
	2017			2016			2015

	($ in thousands)
Cash paid for interest	$	14,786		$	17,451		$	12,755
Cash paid for income taxes, net of refunds	$	(21	)	$	221		$	937
Purchases of PP&E and intangible assets accrued but not paid at year-end	$	12,404		$	1,170		$	4,364
Purchases of PP&E accrued in a prior period and paid in the current period	$	170		$	3,364		$	5,238
Distribution equivalent rights accrued, net of payments	$	—		$	(349	)	$	618
Capitalized reclamation costs, net of amounts acquired in business combination	$	—		$	—		$	113

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ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

As of the end of the period covered by this report, we carried out an evaluation, under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures, as such term is defined under Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as amended, or the Exchange Act. Based on that evaluation, our management, including our Chief Executive Officer and our Chief Financial Officer, has concluded that the design and operation of our disclosure controls and procedures were adequate and effective as of the end of the period covered by this report.

Management’s Report on Internal Control Over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rule 13a-15(f) and 15(d) - 15(f) under the Exchange Act). Our internal control system is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Internal control over financial reporting includes reasonable assurance that:


•	pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets;


•	provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorizations of management and the board of directors of our general partner; and


•	provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Projections of any evaluation of effectiveness to future periods are subject to the risks that controls may become inadequate because of changes in conditions or that the degree of compliance with the policies or procedures may deteriorate.

Management assessed the effectiveness of our internal control over financial reporting, as of December 31, 2017 , and has concluded that such internal control over financial reporting was effective as of that date. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission, or COSO, in the Internal Control - Integrated Framework (2013).

The effectiveness of our internal control over financial reporting as of December 31, 2017 , has been audited by BDO USA, LLP (“BDO”), an independent registered public accounting firm, as stated in their attestation report included in this Annual Report on Form 10-K.

Changes in Internal Control over Financial Reporting

There were no changes in internal control over financial reporting during the quarter ended December 31, 2017 (as defined by Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors of Emerge Energy Services GP LLC, as General Partner of Emerge Energy Services LP and the Partners of Emerge Energy Services LP

Forth Worth, Texas

Opinion on Internal Control over Financial Reporting

We have audited Emerge Energy LP’s (the “Company’s”) internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (the “COSO criteria”). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2017, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the consolidated balance sheets of the Company as of December 31, 2017, and 2016, the related consolidated statements of operations, partners’ equity, and cash flows for each of the three years in the period ended December 31, 2017, and the related notes and our report dated March 1, 2018 expressed an unqualified opinion thereon.

Basis for Opinion

The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Item 9A, Management’s Report on Internal Control over Financial Reporting”. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit of internal control over financial reporting in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ BDO USA, LLP

Dallas, Texas

March 1, 2018

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ITEM 9B.	OTHER INFORMATION

None.

PART III


ITEM 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Partnership Management

We are managed and operated by the directors and executive officers of our general partner, Emerge Energy Partners GP LLC. Our general partner is not elected by our unitholders and will not be subject to re-election in the future. Our general partner has a board of directors, and our unitholders are not entitled to elect the directors or directly or indirectly participate in our management or operations. Our general partner owes certain fiduciary duties to our unitholders as well as a fiduciary duty to its owners. Our general partner is liable, as general partner, for all of our debts (to the extent not paid from our assets), except for indebtedness or other obligations that are made specifically nonrecourse to it. Whenever possible, we intend to incur indebtedness that is nonrecourse to our general partner.

Our general partner's board of directors has nine directors, four of whom are independent as defined under the independence standards established by the NYSE. Our general partner's board of directors has affirmatively determined that Messrs. Clark, Kelly, and Gottfredson are independent as described in the rules of the Exchange Act. The NYSE does not require a listed publicly traded partnership, such as ours, to have a majority of independent directors on the board of directors of our general partner or to establish a compensation committee or a nominating committee.

Directors and Executive Officers

Directors are appointed for a term of one year and hold office until their successors have been elected or qualified or until the earlier of their death, resignation, removal, or disqualification. Officers serve at the discretion of the board. The following table shows information for the directors and executive officers of our general partner.



Name	Age	Position
Ted W. Beneski	61	Chairman of the Board and Director
Rick Shearer	67	Chief Executive Officer and Director
Deborah Deibert	53	Chief Financial Officer
Warren B. Bonham	55	Vice President and Director
Nadya Kurani	44	Chief Accounting Officer
Kevin Clark	61	Independent Director
Mark Gottfredson	60	Independent Director
Peter Jones	60	Independent Director
Francis J. Kelly, III	61	Independent Director
Eliot E. Kerlin, Jr.	43	Director
Victor L. Vescovo	52	Director

Ted W. Beneski

Ted W. Beneski was elected Chairman of the Board and appointed as a member of the board of directors of our general partner in April 2012. Since May 2002, Mr. Beneski has served as the Chief Executive Officer and Managing Partner of Insight Equity Holdings LLC. Insight Equity has $1.4 billion of capital under management. Mr. Beneski serves as chairman of the board of directors at a number of Insight Equity's portfolio companies, including Direct Fuels and SSS prior to our initial public offering. Prior to founding Insight Equity, Mr. Beneski was a founding principal of the Carlyle Management Group, a private equity group specializing in investments in turnarounds and special situation investment opportunities, and served as Senior Vice President from January 2000 to May 2002. Mr. Beneski was also co-founder of the Dallas office of Bain & Company, or Bain, a global leader in strategy-based management consulting services, and served as a Senior Partner and Managing Director. His tenure at Bain (both in Boston and Dallas) was from September 1985 to December 1999. While at Bain, Mr. Beneski advised Fortune 100 clients across a wide range of industries in the areas of portfolio and business unit strategy, mergers and acquisitions, operational

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improvement, organizational and process redesign, new product introduction and growth strategy. Prior to his time at Bain, Mr. Beneski worked for five years as a commercial banker with Bankers Trust in New York and Shawmut Corporation in Boston.

Mr. Beneski also serves as Chairman or Vice Chairman of the Board at the following Insight Equity portfolio companies: Vision Partners, Hirschfeld Industries, Atwood Holdings, Versatile Processing Group Holdings, A.P. Plasman, Flanders Holdings, MB Precision Holdings, Dustex Holdings and Panolam Holdings. Mr. Beneski also serves on the Board of Trustees of Amherst College and Trinity University. Mr. Beneski received his MBA from Harvard Business School and a BA from Amherst College, majoring in economics.

Mr. Beneski was selected to serve on the board of directors of our general partner due to his affiliation with Insight Equity, his knowledge of the industries in which we operate and his financial and business expertise.

Rick Shearer

Rick Shearer was elected Chief Executive Officer of our general partner in April 2012. Since May 2010, Mr. Shearer has served as President and Chief Executive Officer of SSS. In May 2014, Mr. Shearer was elected to serve on the board of directors of our general partner. Mr. Shearer previously served from March 2007 to May 2010 as President and Chief Executive Officer of Black Bull Resources, a company that specializes in the mining, processing and marketing of industrial minerals that is publicly traded on the TSX Venture Exchange. Mr. Shearer currently serves as the Chairman of the Board of Black Bull Resources. From January 2004 to March 2007, Mr. Shearer served as Director of Excell Minerals, a global stainless steel metals recovery company based in Pittsburgh, Pennsylvania, prior to its acquisition by Harsco Corporation in February 2007. Mr. Shearer also previously served as the President and Chief Operating Officer of U.S. Silica Company Inc., a silica sand supplier, from August 1997 to January 2004.

Mr. Shearer served as Founding Chairman of the Industrial Minerals Association of North America, as Vice Chairman of the National Industrial Sand Association and as a Board Member of the Industrial Minerals Association of Europe from 2003 to 2004. Mr. Shearer has a Bachelor of Science degree from Alderson-Broaddus College and a Masters of Business Administration degree from Eastern Michigan University. He is also a graduate of the Executive Management Program at Harvard University.

Deborah Deibert

Deborah Deibert was elected Chief Financial Officer of our general partner in February 2016. Prior to her election as Chief Financial Officer, Ms. Deibert served as the Chief Accounting Officer of the general partner and as Director of Financial Reporting prior to that role. Prior to her employment with the general partner, Ms. Deibert served as the Senior Director of Financial Reporting of FTS International, Inc. from 2011 until 2013. From 2007 until 2011, Ms. Deibert was Senior Director of SEC Reporting & International Finance of Blockbuster Inc. and previously has held various finance and accounting positions since 1988. Ms. Deibert holds a B.B.A. in accounting from the University of Texas at Arlington. She is licensed as a Certified Public Accountant in the state of Texas.

Warren B. Bonham

Warren B. Bonham was elected Vice President and appointed as a member of the board of directors of our general partner in April 2012. Since February 2012, Mr. Bonham has been a Partner of Insight Equity Holdings LLC. Additionally, Mr. Bonham previously served as President and Chief Executive Officer of Direct Fuels from January 2008 to August 2016 and as President from June 2006 to December 2007. Mr. Bonham also previously served as Vice President of Hirschfeld Steel, a company that specializes in the fabrication of structural steel components for construction projects such as bridges, industrial and nuclear facilities, mass transit systems, and stadiums, from September 2010 to January 2012 and from June 2006 to December 2007. From August 2002 to May 2006, Mr. Bonham served as the Chief Financial Officer of GES Exposition Services, the largest subsidiary of Viad Corporation, a publicly traded exhibition and event services company. Prior to joining GES Exposition Services, Mr. Bonham served as Chief Financial Officer of Electrolux LLC, a private equity owned direct seller of floor care equipment, from August 1998 to July 2002. From 1995 to 1998, Mr. Bonham worked as a Senior Manager at Bain, where he worked on operational improvement cases in many different industries on three different continents.

Mr. Bonham serves on the board of directors at a number of Insight Equity's portfolio companies, including SSS prior to our initial public offering. Mr. Bonham received his MBA from Harvard Business School and his Bachelor of Commerce degree from Queen's University where he graduated first in his class. He is also a licensed Chartered Accountant. Mr. Bonham was selected to serve on the board of directors of our general partner due to his affiliation with Insight Equity, his knowledge of the industries in which we operate and his financial and business expertise.

Nadya Kurani

Nadya Kurani was elected Chief Accounting Officer of our general partner in February 2016. Prior to her election as Chief Accounting Officer, Ms. Kurani served as the Director of Financial Reporting of the general partner and as Financial Reporting Manager prior to that role. Prior to her employment with the general partner, Ms. Kurani served as Financial Reporting Manager

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of Dave & Buster’s Entertainment, Inc. from April 2013 to November 2014. Prior to that role, Ms. Kurani served at American Eagle Airlines as Accounting Manager from February 2012 to April 2013 as Financial Reporting Manager from June 2011 to January 2012. From September 2009 to June 2011, Ms. Kurani served as Financial Reporting Manager at Thomas Group, Inc. and previously has held various accounting positions since 2003. Ms. Kurani holds a B.B.A. in accounting from Midwestern State University. She is licensed as a Certified Public Accountant in the state of Colorado.

Kevin Clark

Kevin Clark has served as a member of our board of directors since March 2013. From January 2002 to May 2014 he taught classes in corporate strategy and accounting at Vanderbilt University as an Adjunct Professor, a Senior Lecturer and an Associate Professor. Prior to joining the faculty at Vanderbilt, Mr. Clark was a partner at Executive Perspectives Inc., an executive education firm focused on strategy, finance and team building, from October 1985 to November 1998. He is the co-managing partner of RG Clark Family Holdings, LLC, serving in that role since November 2011, and also serving as Secretary and Treasurer from September 2000 to the present. He has also served as an officer and/or director for other private companies.

Mr. Clark holds a B.S. in physics from Amherst College and an M.S. in computer and information science from Dartmouth College. Mr. Clark was chosen to serve on the board of our general partner due to his expertise in corporate strategy and accounting.

Peter Jones

Peter Jones joined our board of directors in May of 2014. He is the CEO of Panolam Surface Systems, a leader in the laminate and wall-covering industry, a position he has held since the fourth quarter of 2017. Panolam Surface Systems is 100% owned by an Insight Equity portfolio company. He previously was the CEO of Hirschfeld Industries, a leading fabricator of steel used in bridges, stadiums, airports, and other structures from September 2016 to February 2018. He previously was the CEO of Flanders Corporation, a leader in the air filtration industry, a position he held from July of 2014 until June 2016. Since 2009, Mr. Jones has served as an independent advisor to the owners of a number of private companies while they evaluated investment opportunities, handled the operational impacts of rapid growth, reviewed management compensation plans and other deals with assorted issues. During this time, he was on occasion made an employee of employee leasing companies, such as from March to October 2009 as part of Prestige Employee Administrators and from October 2012 to October 2014 as part of Genesis HR Solutions, Inc. Prior to this period of independent contracting, Mr. Jones was involved in the management at a number of private companies, primarily those owned by venture capital and private equity firms.

From 2002 to 2008 he was the Chief Executive Officer of Prime Advantage Corporation, whose two business units included an industrial buying group and a logistics company. From 2005 to 2007, he was Chief Executive Officer of Longstreth Women’s Sports LLC, one of the leading importers and retailers of field hockey, lacrosse, and softball equipment. From 2000 to 2002 he was Chief Executive Officer and President of Stratys Learning Solutions, Inc., which offered masters level degrees in technical fields though distance learning, as well as professional development courses. Mr. Jones has also run or overseen the transformation of companies in the health care, corporate training, laser, computer sales and service, consumer goods and e-commerce software industries. Mr. Jones spent three years at the start of his career with Bankers Trust Company, including a year-long classroom training program focused on accounting and finance. During and after his MBA, Mr. Jones worked for Bain and Company in their Boston office, evaluating potential acquisitions, operational enhancements, and studying the venture capital and leveraged buy-out industries.

Mr. Jones received his MBA with high distinction from Harvard Business School, where he was a Baker Scholar. He also holds a B.A. and an M.A. from the University of Oxford, where he studied Mathematics. He also serves as a Board Member and President of the United States Men’s Field Hockey Foundation and as a Board Member of the International Masters Hockey Association, both of which are non-profit organizations. Mr. Jones was chosen to serve on the board of our general partner due to his expertise with high growth companies and companies in transition.

Francis J. Kelly, III

Francis J. Kelly, III was appointed as an independent director of our general partner in March 2013. Mr. Kelly is President and CEO of CEOVIEW Branding LLC, a brand strategy consulting firm. Prior to forming CEOVIEW, Mr. Kelly was with Arnold Worldwide, LLC a large advertising agency. Mr. Kelly joined Arnold Worldwide in January 1994 as Chief Marketing officer, and advanced to become President in 2002, CEO in 2006, and eventually Vice Chairman in 2010 until his resignation in 2014. Mr. Kelly has led a number of successful branding strategies for public and private companies while helping Arnold Worldwide shape its strategic and creative philosophy. From 1989 to 1994, Mr. Kelly worked at Leonard Monahan and Lubars, an advertising agency subsequently renamed Leonard Monahan Lubars and Kelly. From 1983 to 1988, Mr. Kelly developed integrated campaigns for national brands while working for Humphrey Browning MacDougall. His career in the field of branding, advertising, and integrated marketing communications also includes time at Young & Rubicam New York.

Mr. Kelly received his MBA from Harvard Business School and his Bachelor of Arts degree from Amherst College. He is the co-author of two business books and has previously served on the boards of the Boston Chamber of Commerce, the Friends of the

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Boston Public Library, the Boston Ad Club and the American Association of Advertising Agencies. Mr. Kelly was selected to serve on the board of directors of our general partner due to his marketing, financial and business expertise.

Mark Gottfredson

Mark Gottfredson was appointed to the Board as independent director of our general partner in March 2015. Mr. Gottfredson was also appointed a member of the Audit Committee of the Board. Mr. Gottfredson is currently a director of Bain & Company’s office in Dallas, Texas, which he founded in 1990. Throughout his career, he has advised chief executives and top-level managers in a wide range of industries. He has served in a number of leadership positions at Bain & Company including as a member of the board of directors and as the Global Head of Bain’s Performance Improvement Practice. Currently, he heads Bain’s North American Automotive Practice. In 2005, Mr. Gottfredson was named to Consulting Magazines list of Top 25 Consultants globally. He has been published extensively in publications such as the Harvard Business Review, European Strategy, and the World Business Review. His book for general managers, titled The Breakthrough Imperative and published by Harper Collins, debuted in spring 2008. Mr. Gottfredson serves on a number of for profit and non-profit boards, including Vista Outdoor Inc., TBM Consulting Group, the Circle 10 Council with the Boy Scouts of America, the Longhorn Council for the Boy Scouts of America, the BYU Marriot School National Advisory Council, and Bain & Company.

Mr. Gottfredson obtained his MBA from Harvard Business School in 1981, where he graduated with high distinction and was named a Baker Scholar. He received a Bachelor of Arts degree from Brigham Young University in Japanese, where he graduated magna cum laude. Mr. Gottfredson was selected to serve on the Board of the general partner due to his advisory experience and financial and business expertise.

Eliot E. Kerlin, Jr.

Eliot E. Kerlin Jr. was appointed as a member of the board of directors of our general partner in March 2013. Mr. Kerlin is a Partner at Insight Equity Holdings LLC and has been a member of the firm since July 2005. During his time at Insight Equity Holdings LLC, Mr. Kerlin has led a number of acquisitions, recapitalizations, financings, and operational improvement initiatives at portfolio companies. During 2004, Mr. Kerlin served as a turnaround manager for Bay State Paper Company, a containerboard and craft paper manufacturer. From 2000 to 2003, Mr. Kerlin worked as a Senior Associate at Jupiter Partners, a middle market private equity fund. He began his career as an investment banker at Merrill Lynch Pierce Fenner & Smith.

Mr. Kerlin serves as a board member for a number of Insight Equity's portfolio companies, including SSS prior to our initial public offering. Mr. Kerlin also serves on the Board of Directors of the DFW Private Equity Forum, Casa Del Lago, and was formerly a director of the BraveLove and the Prison Entrepreneurship Program. Mr Kerlin received his MBA from Harvard Business School where he graduated with Distinction. He also received his BBA in Finance from Texas A&M University where he graduated with honors. Mr. Kerlin also serves on several non-profit, community and professional boards of directors. Mr. Kerlin was selected to serve on the board of directors of our general partner due to his affiliation with Insight Equity, his knowledge of the industries in which we operate and his financial and business expertise.

Victor L. Vescovo

Victor L. Vescovo was appointed as a member of the board of directors of our general partner in April 2012. Since January 2003, Mr. Vescovo has served as the Chief Operating Officer and Managing Partner of Insight Equity Holdings LLC, which he co-founded with Mr. Beneski. From 1999 to 2001, Mr. Vescovo was Vice President of Product Development of Military Advantage, a venture-backed company sold to Monster Worldwide, Inc. in 2004. From 1994 to 1999, he was a Senior Manager at Bain where he focused on merger integration and operational improvement cases. Mr. Vescovo previously worked in the mergers & acquisitions department of Lehman Brothers Holdings Inc. where he was responsible for company due diligence and transaction execution, as well as working overseas in the Middle East advising the Saudi government on business investments from 1991 to 1992.

Mr. Vescovo also serves as a chairman or vice chairman of the Board for f all of Insight Equity's portfolio companies, including Consolidated Construction Investment Holdings LLC, VPG Group Holdings LLC, APP Holdings LP, Micross Investment Holdings LLC, MB Precision Investment Holdings LLC, Dustex Holdings LLC, Panolam Investment Holdings LLC, Riverbend Foods Investment Holdings LLC, and Virtex Investment Holdings LLC. Mr. Vescovo received his MBA from Harvard Business School where he graduated as a Baker Scholar. He also received a Master's Degree from the Massachusetts Institute of Technology and earned a double major Bachelor of Arts in economics and political science from Stanford University.

Additionally, Mr. Vescovo served 20 years in the U.S. Navy Reserve as an intelligence officer, retiring in 2014 as a Commander (O-5). He participated at the staff level in combat operations in Europe and Asia, and served for more than a year after 9/11 supporting counter-terrorism efforts overseas. Mr. Vescovo was selected to serve on the board of directors of our general partner due to his affiliation with Insight Equity, his knowledge of the industries in which we operate and his financial and business expertise.

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Corporate Governance

The board of directors of our general partner has adopted corporate governance guidelines to assist it in the exercise of its responsibilities to provide effective governance over our affairs for the benefit of our unitholders. In addition, we have adopted a code of business conduct and ethics, which sets forth legal and ethical standards of conduct for all our officers, directors, and employees. The corporate governance guidelines, the code of business conduct and ethics and the charters of our audit and conflicts committees are available on our website at www.emergelp.com and in print without charge to any unitholder who requests any of them. A unitholder may make such a request in writing by mailing such request to Investor Relations, Emerge Energy Services LP, 5600 Clearfork Main Street, Suite 400, Fort Worth, Texas 76109. Amendments to, or waivers from, the code of business conduct and ethics will also be available on our website and reported as may be required under SEC rules; however, any technical, administrative or other non-substantive amendments to the code of business conduct and ethics may not be posted. Please note that the preceding Internet address is for information purposes only and is not intended to be a hyperlink. Accordingly, no information found or provided at that Internet address or at our website in general is intended or deemed to be incorporated by reference herein.

Conflicts Committee

Our partnership agreement provides for the Conflicts Committee, as circumstances warrant, to review conflicts of interest between us and our general partner or between us and affiliates of our general partner. The Conflicts Committee, consisting solely of independent directors, determines if the resolution of a conflict of interest that has been presented to it by our general partner is fair and reasonable to us. The members of the Conflicts Committee may not be executive officers or employees of our general partner or directors, executive officers or employees of its affiliates. In addition, the members of the Conflicts Committee must meet the independence and experience standards established by the NYSE and the Exchange Act. Messrs. Clark and Kelly serve as the members of the Conflicts Committee. Mr. Kelly serves as the chair of our Conflicts Committee.

Audit Committee

The board of directors of our general partner has established an audit committee, or Audit Committee, that complies with the NYSE requirements and Section 3(a)(58)(A) of the Exchange Act. Our general partner is generally required to have at least three independent directors serving on its board at all times. Messrs. Clark, Kelly, and Gottfredson are independent directors and serve as the members of the Audit Committee. The board of directors of our general partner has also determined that Mr. Clark, who serves as the chairman of the Audit Committee, and also Messrs. Kelly and Gottfredson, each have such accounting or related financial management expertise sufficient to qualify him as an audit committee financial expert in accordance with Item 407(d) of Regulation S-K.

The Audit Committee meets on a regularly scheduled basis with our independent accountants at least four times each year and is available to meet upon the request of any committee member. The Audit Committee has the authority and responsibility to review our external financial reporting, to review our procedures for internal auditing and the adequacy of our internal accounting controls, to consider the qualifications and independence of our independent accountants, to engage and resolve disputes with our independent accountants, including the letter of engagement and statement of fees relating to the scope of the annual audit work and special audit work that may be recommended or required by the independent accountants, and to engage the services of any other advisors and accountants as the Audit Committee deems advisable. The Audit Committee reviews and discusses the audited financial statements with management, discusses with our independent auditors matters required to be discussed by Public Company Accounting Oversight Board Auditing Standard No. 16 (Communications with Audit Committees) and Rule 3520 (Auditor Independence), and makes recommendations to the board of directors of our general partner regarding the inclusion of our audited financial statements in this Annual Report on Form 10-K.

The Audit Committee is authorized to recommend periodically to the board of directors any changes or modifications to its charter that the Audit Committee believes may be required or desirable.

Presiding Director at Meetings of Non-Management Directors.

Section 303A.03 of the NYSE Listed Company Manual requires “non-management directors” to schedule regular executive sessions with members of management present. “Non-management directors” are defined in Section 303A.03 as all directors who are not executive officers. The Partnership schedules executive sessions on a regular basis in which the Partnership's non-management directors meet without management participation. Mr. Kevin Clark serves as the presiding director at such sessions. The Board of Directors is responsible for determining whether or not each director is independent. The Board of Directors has adopted the director independence standards contained in Section 303A.02 of the NYSE’s Listed Company Manual for the purposes of satisfying the NYSE’s applicable governance requirements.

Communication with the Board of Directors

A holder of our units or other interested party who wishes to communicate with the non-management directors or independent directors of our general partner may do so by writing in an envelope marked “Confidential” to the Independent Members of the Board, at 5600 Clearfork Main Street, Suite 400, Fort Worth, Texas, 76109.

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Section 16(a) Beneficial Ownership Reporting Compliance

Section 16(a) of the Exchange Act requires our general partner's board of directors and executive officers, and persons who own more than 10 percent of a registered class of our equity securities, to file with the SEC and any exchange or other system on which such securities are traded or quoted initial reports of ownership and reports of changes in ownership of our common units and other equity securities. Officers, directors and greater than 10 percent unitholders are required by the SEC's regulations to furnish to us and any exchange or other system on which such securities are traded or quoted with copies of all Section 16(a) forms they filed with the SEC. To our knowledge, based solely on a review of the copies of such reports furnished to us and written representations that no other reports were required, we believe that all reporting obligations of our general partner's officers, directors and greater than 10 percent unitholders under Section 16(a) were satisfied during the year ended December 31, 2017 , except as described below.

Due to administrative oversight, Ms. Deibert did not timely report the exempt withholding of common units to satisfy her tax withholding obligations related to the vesting of restricted units on January 1, 2017, and October 26, 2017, and did not timely report the exempt grant of restricted units to her on December 29, 2017. Ms. Deibert reported the withholding and the grant in Forms 4 filed on January 4, 2017, and February 28, 2018, respectively.

Due to administrative oversight, Ms. Kurani did not timely report the exempt withholding of common units to satisfy her tax withholding obligations related to the vesting of restricted units on January 1, 2017, and did not timely report the exempt grant of restricted units to her on December 29, 2017. Ms. Kurani reported the withholding and the grant in Forms 4 filed on January 4, 2017, and February 28, 2018, respectively.

Due to administrative oversight, Messrs. Clark, Gottfredson, Jones and Kelly did not timely report the exempt grant of restricted units to each of them on May 14, 2017. Messrs. Clark, Gottfredson, Jones and Kelly each reported the grant in a Form 4 filed on August 17, 2017, August 17, 2017, August 25, 2017, and August 17, 2017, respectively.

Due to administrative oversight, Mr. Shearer did not timely report the exempt withholding of common units to satisfy his tax withholding obligation related to the vesting of restricted units on July 1, 2017, and did not timely report the exempt grant of restricted units to him on December 29, 2017. Mr. Shearer reported the withholding and the grant in Forms 4 filed on July 5, 2017, and February 28, 2018, respectively.


ITEM 11.	COMPENSATION DISCUSSION AND ANALYSIS

The board of directors of our general partner develops our executive compensation policies and determines the amounts and elements of compensation for our named executive officers. This Compensation Discussion and Analysis describes our executive compensation programs for our named executive officers for the 2017 fiscal year, who were:


•	Rick Shearer, Chief Executive Officer of Emerge Energy Services GP LLC, our general partner;


•	Deborah Deibert, Chief Financial Officer of our general partner;


•	Warren Bonham, Vice President of our general partner; and


•	Nadya Kurani, Chief Accounting Officer of our general partner.

Compensation Principles and Objectives

Our overall compensation program is structured to attract, motivate and retain highly qualified executive officers by paying them competitively, consistent with our success and their contribution to that success. Our ability to excel depends on the skill, creativity, integrity, and teamwork of our employees. We believe compensation should be structured to ensure that a portion of compensation opportunity will be related to factors that directly and indirectly influence long-term unitholder value. Our compensation philosophy has been driven by a number of factors that are closely linked with our broader strategic objectives.

The board of directors of our general partner believes that compensation paid to our named executive officers should be aligned with our performance on both a short-term and long-term basis, linked to results intended to create value for unitholders, and that such compensation should assist us in attracting and retaining key executives critical to our long-term success.

In establishing compensation for executive officers, the following are the objectives of the board of directors of our general partner:


•	align officer and unitholder interests by providing a significant portion of total compensation opportunities for senior management in the form of equity awards and bonuses awarded based on the board of directors of our general partner’s review of company and individual performance; and


•	ensure executive officer compensation is competitive within the marketplace in which we compete for executive talent by relying on the board of directors of our general partner’s judgment, expertise and personal experience with other similar companies.

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Determination of Compensation

The board of directors of our general partner is charged with the primary authority to determine the compensation available to our executive officers. Based on the directors’ collective understanding of compensation practices in similar companies in the frac sand industry, our executive compensation package consists of the following elements, in addition to the employee benefit plans in which all employees may participate:


•	Base salary: compensation for ongoing services throughout the year.


•	Annual performance-based compensation and discretionary bonuses: annual incentive bonus based on the achievement of pre-established targets and/or discretionary objectives, each to recognize and reward achievement of corporate and individual performance.


•	Long-term incentive compensation programs: equity compensation to provide an incentive to our named executive officers to manage us from the perspective of an owner with an equity stake in the business.


•	Severance and change in control benefits: remuneration paid to certain executives in the event of a qualifying termination of employment and/or change in control.

To aid the board of directors of our general partner in making its determination, our Chief Executive Officer provides recommendations annually to the board of directors of our general partner regarding the compensation of all executive officers (other than himself) based on the overall corporate achievements during the period being assessed and his knowledge of the individual contributions to our success by each named executive officer. The overall performance of our named executive officers as a team is reviewed annually by the board of directors of our general partner.

We set base salary and annual bonus structures and determine grants of equity awards based on the board of directors of our general partner’s understanding of compensation practices in the frac sand industry and such directors’ experiences as seasoned executives, consultants, members of the board of directors of our general partner, or investors in similar frac sand industry companies. In addition, from time to time we may rely on compensation survey data provided by an independent compensation consultant.

Elements of Executive Compensation

Base Salaries

Base salaries of our named executive officers (other than our Chief Executive Officer) are recommended and reviewed periodically by our Chief Executive Officer, and the initial base salary for each named executive officer is approved by the board of directors of our general partner. Base salaries for the named executive officers are reviewed periodically by the board of directors of our general partner, and adjustments are made generally in accordance with the considerations described above and to maintain base salaries at competitive levels. These periodic reviews consider, among other things, the scope of an executive’s responsibilities, individual contribution, experience and sustained performance, general economic conditions, industry specific business conditions, base salaries for comparable positions in similar industries, the tenure of the officers, and base salaries of the officers relative to one another. Decisions regarding salary increases may take into account the named executive officer’s current salary and other compensation, and the amounts paid to individuals in comparable positions at our peer companies.

Pursuant to the terms of Mr. Shearer’s employment letter agreement with our general partner, the board of directors of our general partner will review Mr. Shearer’s annual base salary at least annually in the normal course of business, and may increase Mr. Shearer’s base salary in its sole discretion after giving consideration to base salaries of similarly-situated chief executive officers. Based on changes in company performance and increases in the cost of living, the board of directors decided to increase Mr. Shearer’s annual base salary from $500,000 to $525,000, effective November 1, 2016, in connection with a second amendment to his employment letter agreement.

In January 2017, the board of directors of our general partner approved base salary increases for each of our other named executive officers of 5% (or 10% with respect to Ms. Kurani), effective January 1, 2017. These increases were determined primarily based on economic conditions, the board members’ understanding of base salaries for comparable positions at peer companies, officer tenure, and base salaries of the officers relative to one another.

The following table sets forth our named executive officers’ 2017 annual base salaries. The actual base salaries paid to our named executive officers during 2017 are set forth in the “Summary Compensation Table” below:

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Named Executive Officer		2017 Annual Base Salary
Rick Shearer		$525,000
Deborah Deibert		$294,010
Warren Bonham		$220,497
Nadya Kurani		$181,507

In December 2017, the board of directors of our general partner approved base salary increases for each of our named executive officers of 5% (or 8% with respect to Ms. Kurani), effective January 1, 2018. These increases were determined primarily based on economic conditions, the board members’ understanding of base salaries for comparable positions at peer companies, officer tenure, and base salaries of the officers relative to one another.

Annual Bonuses

In addition to base salaries, our executives are also eligible to receive annual incentive bonuses. For 2017, annual incentive bonuses were targeted at the percentage of each executive’s annual base salary shown below.



Named Executive Officer		2017 Target Bonus as a Percent of Base Salary
Rick Shearer		80%
Deborah Deibert		50%
Warren Bonham		40%
Nadya Kurani		40%

For 2017, each of our named executive officers was eligible to receive an annual incentive bonus based on achievement of pre‑established adjusted EBITDA targets for Emerge. The applicable threshold and target levels and associated payouts are listed below, with achievement between the threshold level and target level determined by straight-line interpolation. There was no maximum funding level under the 2017 annual incentive bonus plan.



Named Executive Officer	Adjusted EBITDA	Payout (as a percentage of base salary)
Rick Shearer
Threshold	$(10,000,000)	60%
Target	$—	80%
Deborah Deibert
Threshold	$(10,000,000)	37.5%
Target	$—	50%
Warren Bonham
Threshold	$(10,000,000)	30%
Target	$—	40%
Nadya Kurani
Threshold	$(10,000,000)	30%
Target	$—	40%

Adjusted EBITDA used by management for each named executive officers’ bonus calculation was calculated as: net income plus interest expense, tax expense, depreciation, depletion and amortization expense, non-cash charges and unusual or non-recurring charges less interest income, tax benefits, and selected gains that are unusual or non-recurring.

Based on the 2017 adjusted EBITDA of $45.0 million achieved by Emerge, Messrs. Shearer and Bonham and Mses. Deibert and Kurani earned annual incentive bonuses equal to $891,595, $187,232, $312,069, and $154,124, respectively.

Equity Awards

The goals of our long-term, equity-based incentive awards are to align the interests of our named executive officers with the interests of our common unitholders. Because vesting is generally based on continued service, our equity-based incentives also encourage the retention of our named executive officers during the award vesting period. In determining the size of the long-term equity incentives to be awarded to our named executive officers, we take into account a number of factors, such as the reason for the grant, the value of existing equity-based awards (if any), individual performance history, and prior financial contributions to us.

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To reward and retain our named executive officers in a manner that aligns their interests with our unitholders’ interests, we have historically used phantom units as the incentive vehicle for long-term compensation. We have granted phantom units in connection with specific events, such as our IPO, hirings or promotions. Because employees realize increased value from phantom units if our unit price increases, we believe phantom units provide meaningful incentives to achieve increases in the value of our units over time. Grants of phantom units are typically accompanied by grants of distribution equivalent rights (“DERs”), which entitle the holder of the award to receive distributions in an amount equal to any distributions to our common unitholders.

Phantom unit awards are typically subject to time-based vesting conditions and/or performance-based vesting conditions related to our unit price. Vesting may also be tied to other conditions, such as the sale or disposition of common units held by Insight Equity following our IPO. In addition, phantom unit awards may be subject to accelerated vesting in connection with a change in control and/or upon a qualifying termination of service.

In January 2017, we granted Mses. Deibert and Kurani phantom unit awards covering 7,500 phantom units and 3,750 phantom units, respectively. The awards vest with respect to 50% of the units subject thereto on each of the first and second anniversaries of January 1, 2017, subject to the executive’s continued service with our general partner, or immediately prior to a change in control (subject to the executive remaining in continuous service with our general partner until immediately prior to such change in control). In addition, if the executive’s employment is terminated without cause, a prorated number of unvested phantom units will vest.

Pursuant to the terms of Mr. Shearer’s employment letter agreement with our general partner, in December 2017, we granted Mr. Shearer a phantom unit award covering 96,389 phantom units. The award will vest with respect to 50% of the units subject thereto on each of the first and second anniversaries of November 1, 2017, subject to Mr. Shearer’s continued service with our general partner, or immediately prior to a change in control (subject to Mr. Shearer remaining in continuous service with our general partner until immediately prior to such change in control). In addition, if Mr. Shearer’s employment is terminated without cause, a prorated number of unvested phantom units will vest.

In December 2017, we also granted Mses. Deibert and Kurani phantom unit awards covering 10,000 phantom units and 5,000 phantom units, respectively. The awards will vest with respect to 50% of the units subject thereto on each of the first and second anniversaries of January 1, 2018, subject to the executive’s continued service with our general partner, or immediately prior to a change in control (subject to the executive remaining in continuous service with our general partner until immediately prior to such change in control). In addition, if the executive’s employment is terminated without cause, a prorated number of unvested phantom units will vest.

Severance and Change in Control Arrangements

Each of our named executive officers, other than Mr. Bonham, is eligible for severance benefits pursuant to their respective employment letters. We believe that this protection serves to encourage continued attention and dedication to duties without distraction arising from the possibility of a termination of employment or change in control, and provides the business with a smooth transition in the event of such a termination of employment. These severance arrangements are designed to retain these named executive officers in their respective key positions as we compete for talented executives in the marketplace where such protections are commonly offered. For a detailed description of the severance provisions contained in our named executive officers’ employment letters, and other severance or change in control protections, see “Potential Payments Upon Termination or Change in Control” below. We do not offer Mr. Bonham severance benefits because of his association with Insight Equity.

Other Elements of Compensation and Perquisites

All of our full-time employees in the United States, including our named executive officers, are eligible to participate in our 401(k) plan and our health and welfare plans (including medical, dental, short-term and long-term disability, accidental death and dismemberment and life insurance). Our named executive officers participate in these plans on the same basic terms as all other similarly situated employees.

Through its subsidiaries, our general partner maintains a 401(k) retirement savings plans for its employees who satisfy certain eligibility requirements. Mr. Bonham does not participate in our 401(k) retirement savings plans because of his association with Insight Equity. The Internal Revenue Code of 1986, as amended (the “Code”), allows eligible employees to defer a portion of their compensation, within prescribed limits, on a pre-tax basis through contributions to the 401(k) plan. We believe that providing a vehicle for tax-deferred retirement savings though a 401(k) plan adds to the overall desirability of our executive compensation package and further incentivizes our employees, including the named executive officers, in accordance with our compensation policies.

In addition to the benefits provided to all of our full-time employees, Mr. Shearer is also entitled to receive company-paid annual physical exams, not to exceed $3,000 per year, which are supplemental to the health benefits provided to employees of our general partner generally. Effective as of January 1, 2018, Mr. Shearer also became entitled to receive a monthly automobile allowance equal to $1,917.

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In the future, we may provide perquisites or other personal benefits in limited circumstances, such as where we believe it is appropriate to assist an individual named executive officer in the performance of his duties, to make our named executive officers more efficient and effective, and for recruitment, motivation, and/or retention purposes. Future practices with respect to perquisites or other personal benefits for our named executive officers will be approved and subject to periodic review by the board of directors of our general partner.

Tax and Accounting Considerations

Section 280G of the Code

Section 280G of the Code disallows a tax deduction with respect to excess parachute payments to certain executives of companies which undergo a change in control. In addition, Section 4999 of the Code imposes a 20% excise tax on the individual with respect to the excess parachute payment. Parachute payments are compensation linked to or triggered by a change in control and may include, but are not limited to, bonus payments, severance payments, certain fringe benefits, and payments and acceleration of vesting from long-term incentive plans including restricted units and other equity-based compensation. Excess parachute payments are parachute payments that exceed a threshold determined under Section 280G of the Code based on the executive’s prior compensation. In approving the compensation arrangements for our named executive officers in the future, the board of directors of our general partner will consider all elements of the cost to the Company of providing such compensation, including the potential impact of Section 280G of the Code. However, the board of directors of our general partner may, in its judgment, authorize compensation arrangements that could give rise to loss of deductibility under Section 280G of the Code and the imposition of excise taxes under Section 4999 of the Code when it believes that such arrangements are appropriate to attract and retain executive talent.

Accounting Standards

ASC Topic 718, Compensation-Stock Compensation (“ASC 718”) requires us to recognize an expense for the fair value of equity-based compensation awards. Grants of phantom units and restricted units under our equity incentive award plan are accounted for under ASC 718. The board of directors of our general partner regularly considers the accounting implications of significant compensation decisions, especially in connection with decisions that relate to our equity incentive award plan. As accounting standards change, we may revise certain programs to appropriately align accounting expenses of our equity awards with our overall executive compensation philosophy and objectives.

Summary Compensation Table



Name and Principal Position	Salary ($)	Bonus ($)	Stock Awards ($)(1)	Non-Equity Incentive Plan Compensation ($) (2)	All Other Compensation ($)(4)	Total ($)
Rick Shearer
Chief Executive Officer
2017	525,000	—	787,498	891,595	9,794	2,213,887
2016	510,961	50,000	787,495	—	15,800	1,364,256
2015	475,000	15,000	999,928	—	28,223	1,518,151
Deborah Deibert
Chief Financial Officer
2017	293,471	—	166,175	312,069	12,762	784,477
2016	273,654	46,666	45,920	—	9,983	376,223
2015	206,423	6,750	67,260	—	14,864	295,297
Warren Bonham
Vice President
2017	220,093	—	—	187,232	2,904	410,229
2016	210,000	—	—	51,644	3,130	264,774
2015	210,000	—	—	14,151	3,665	227,816
Nadya Kurani (3)
Chief Accounting Officer
2017	180,872	—	83,088	154,124	9,084	427,168
2016	160,385	27,500	22,960	—	7,194	218,039

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(1)

The amounts illustrated in this column reflect the aggregate grant date fair value of phantom unit awards made in 2017. The values are calculated in accordance with GAAP. For a discussion of the assumptions used to calculate the value of all phantom unit awards made to named executive officers, refer to Note 16 to our financial statements included in this Annual Report on Form 10-K for the year ended December 31, 2017.


(2)	For 2017, the amounts include annual incentive bonus earned in connection with the pre-established adjusted EBITDA targets. Annual incentive bonuses earned in 2017 will be paid by March 15, 2018.


(3)	Ms. Kurani was not a “named executive officer” of the company in 2015.

(4)

The following table sets forth the amount of each other item of compensation paid to, or on behalf of, our named executive officers in 2017 included in the “All Other Compensation” column. Amounts for each other item of compensation are valued based on the aggregate incremental cost to us, in each case without taking into account the value of any income tax deductions for which we may be eligible.



Name	Company Contributions to 401(k) Plan ($)	Company Contributions to Health Savings Account ($)	Reimbursement for Executive Physical Allowance ($)
Rick Shearer	3,644	3,150	3,000
Deborah Deibert	9,612	3,150	—
Warren Bonham	—	—	2,904
Nadya Kurani	5,934	3,150	—

Grants of Plan-Based Awards in 2017

The following table sets forth information regarding grants of plan-based awards made to our named executive officers during the year ended December 31, 2017 :



		Estimated Possible Payouts under Non-Equity Incentive Plan Awards (1)
Name	Grant Date	Threshold ($)	Target ($)	Maximum ($)	All Other Stock Awards: Number of Units (#) (2)	Grant Date Fair Value of Stock Awards ($) (3)
Rick Shearer	—	$315,000	$420,000	—	—	—
Rick Shearer	12/29/2017	—	—	—	96,389	787,498
Deborah Deibert	—	$110,254	$147,005	—	—	—
Deborah Deibert	1/4/2017			—	7,500	94,275
Deborah Deibert	12/29/2017	—	—	—	10,000	71,900
Warren Bonham	—	$66,149	$88,199	—	—	—
Nadya Kurani	—	$54,452	$72,603	—	—	—
Nadya Kurani	1/4/2017	—	—	—	3,750	47,138
Nadya Kurani	12/29/2017	—	—		5,000	35,950

(1)

Amounts shown in these columns represent each named executive officer’s non-discretionary incentive bonus opportunity under the 2017 bonus programs in which such officers participated. The “Target” amount represents the named executive officer’s target bonus if the performance goal under the bonus program was achieved at the target level and the “Threshold” amount represents named executive officer’s minimum bonus if the performance goal under the bonus program was achieved at the minimum level. There was no maximum funding level under the 2017 bonus programs.


(2)	Consists of time-base vesting phantom units awards which the board of directors of our general partner approved in 2017. For details of each award, see “Elements of Executive Compensation - Equity Awards” above.


(3)	The amounts illustrated in this column reflect the aggregate grant date fair value of phantom unit awards made in 2017. The values are calculated in accordance with GAAP.

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Narrative Disclosure to Summary Compensation Table

Employment Letters

Our general partner is a party to employment letters with Mr. Shearer and Mses. Deibert and Kurani, each of which is described below. We have not entered into an employment letter or employment agreement with Mr. Bonham.

Rick Shearer. Our general partner and Mr. Shearer are parties to an amended employment letter agreement, dated May 29, 2013 (as amended effective April 15, 2016, and November 2, 2016, the “Amended Shearer Letter”), that provides for Mr. Shearer’s employment as Chief Executive Officer of our general partner. The Amended Shearer Letter amends and restates the employment letter agreement between SSS and Mr. Shearer, dated March 23, 2010, and amended May 17, 2011, which was assigned to our general partner in connection with our IPO. In April 2016, the Amended Shearer Letter was amended so that it will expire on December 31, 2020 (extended from December 31, 2016), unless earlier terminated. The term of the Amended Shearer Letter is subject to automatic one-year renewals unless either our general partner or Mr. Shearer gives written notice of termination at least 60 days prior to the end of the applicable term.

Under the Amended Shearer Letter, Mr. Shearer’s annual base salary is $525,000, which the board of directors of our general partner will review at least annually in the normal course of business and may increase in its sole discretion after giving consideration to base salaries of similarly-situated chief executive officers, and Mr. Shearer is eligible to receive an annual discretionary cash performance bonus under any general partner bonus plan or program applicable to similarly-situated employees. The Amended Shearer Letter also provides that Mr. Shearer is eligible to participate in the welfare benefit plans maintained by our general partner on the same basis as similarly-situated employees, and is entitled to annual physical examinations, paid by our general partner, in an amount up to $3,000 per year.

In November 2016, the Amended Shearer Letter was amended to provide that Mr. Shearer will be granted, on each of November 1, 2017 (the “2017 Award”) and November 1, 2018 (subject to the approval of the board of directors of our general partner and Mr. Shearer’s continued employment through the applicable grant date), a phantom unit award covering a number of phantom units equal to (i) with respect to the November 1, 2017, phantom unit award, one and one-half his then-current annual base salary and (ii) with respect to the November 1, 2018, phantom unit award, one-half his then-current base salary on the second grant date, in each case, divided by the per-unit closing price of a unit on the applicable grant date. Each of the phantom unit awards will vest with respect to 50% of the units subject thereto on each of the first and second anniversaries of the applicable grant date, subject to Mr. Shearer’s continued service. In addition, (i) any of these then-outstanding phantom unit awards will accelerate and vest in full immediately prior to a change in control and (ii) if Mr. Shearer is terminated by us without cause, then a prorated number of unvested phantom units will vest with respect to any of these then-outstanding phantom unit awards. In December 2017, we granted to Mr. Shearer the 2017 Award, which will vest in 50% installments on each of November 1, 2018, and November 1, 2019, rather than on the anniversaries of the grant date.

Deborah Deibert. On October 29, 2015, we entered into a promotion letter with Deborah Deibert pursuant to which Ms. Deibert began serving as Chief Accounting Officer of our general partner (the “Deibert Letter”) effective November 13, 2015. Under the Deibert Letter, Ms. Deibert’s initial annual salary was $225,000 and she was eligible to receive an annual cash bonus for 2015 targeted at 45% of her base salary. Ms. Deibert is also entitled to participate in the health and welfare benefit plans maintained by our general partner on the same basis as similarly-situated employees. On February 8, 2016, in connection with Ms. Deibert’s appointment to Chief Financial Officer, we amended the Deibert Letter (as amended due to her promotion to CFO, the “Amended Deibert Letter”) to increase Ms. Deibert’s annual salary to $280,000, to increase Ms. Deibert’s target annual cash bonus to 50% of her base salary and to enhance Ms. Deibert’s severance benefits.

Nadya Kurani. On February 8, 2016, we entered into a promotion letter with Nadya Kurani pursuant to which Ms. Kurani began serving as Chief Accounting Officer of our general partner (the “Kurani Letter”) effective February 8, 2016. Under the Kurani Letter, Ms. Kurani’s annual salary is $165,000 and she was eligible to receive an annual cash bonus for 2016 targeted at 40% of her base salary. Ms. Kurani is also entitled to participate in the health and welfare benefit plans maintained by our general partner on the same basis as similarly-situated employees. Prior to Ms. Kurani’s appointment to Chief Accounting Officer, her annual salary was $125,000 and her target annual cash bonus was 25% of her annual salary.

The Amended Shearer Letter, the Amended Deibert Letter and the Kurani Letter also provide or provided for certain payments and benefits upon a termination of employment in certain circumstances by our general partner without “cause” (as defined in the applicable employment letter), as described under “Potential Payments Upon a Termination or Change of Control” below:

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Outstanding Equity Awards at December 31, 2017

The following table summarizes the number of shares of our common units underlying outstanding equity incentive plan awards for each named executive officer as of December 31, 2017 :



Name	Grant Date	Number of Units That Have Not Vested (#)	Market Value of Units That Have Not Vested ($)(1)	Equity Incentive Plan Awards: Number of Unearned Units That Have Not Vested (#)	Equity Incentive Plan Awards: Market or Payout Value of Unearned Units That Have Not Vested ($)(2)
Rick Shearer	7/1/2015 (3)	4,541	32,650	—	—
	7/1/2015 (4)	—	—	13,623	97,949
	11/1/2016 (5)	30,738	221,006	—	—
	11/1/2017 (5)	96,389	693,037	—	—
Deborah Deibert	1/1/2015 (6)	200	1,438	—	—
	10/26/2015 (6)	2,333	16,774	—	—
	2/8/2016 (7)	7,000	50,330	—	—
	1/1/2017 (8)	7,500	53,925	—	—
	12/29/2017 (8)	10,000	71,900	—	—
Warren Bonham	5/4/2013 (9)	—	—	82,974	1,342,519
Nadya Kurani	2/8/2016 (7)	3,500	25,165	—	—
	1/1/2017 (8)	3,750	26,963	—	—
	12/29/2017 (8)	5,000	35,950	—	—


(1)	The market value of phantom units that have not vested is calculated based on the closing trading price of our common units as reported on the New York Stock Exchange on December 29, 2017 ($7.19).


(2)	The payout value for Mr. Bonham includes $745,936 of outstanding DERs that were accrued as of December 31, 2017 , and will be paid once the underlying phantom unit award and associated DERs vest.


(3)	This phantom unit award vests, subject to continued service, in equal installments on the first, second and third anniversaries of the vesting commencement date (July 1, 2015). In addition, this phantom unit award may be subject to full or pro-rated accelerated vesting immediately prior to a change in control or upon a qualifying termination of service.

(4)

This phantom unit award vests based on achievement of the following unit price targets, and subject to continued service: (i) 50% on the date our per-unit closing price equals or exceeds 1.25 times the per-unit closing price on the grant date ($36.70); and (ii) 50% on the date our per-unit closing price equals or exceeds 2.0 times the per-unit closing price on the grant date. In addition, this phantom unit award may be subject to accelerated vesting immediately prior to a change in control.

(5)

This phantom unit award vests, subject to continued service, in equal installments on the first and second anniversaries of the vesting commencement date (November 1, 2016, with respect to the award granted on November 1, 2016, and November 1, 2017, with respect to the award granted on December 29, 2017). In addition, this phantom unit award may be subject to full or pro-rated accelerated vesting immediately prior to a change in control or upon a qualifying termination of service.

(6)

These phantom unit awards vest, subject to continued service, in equal installments on the first, second, and third anniversaries of the vesting commencement date (January 1, 2015, with respect to the award granted on January 1, 2015 and October 1, 2015, with respect to the award granted on October 26, 2015). In addition, these phantom unit awards may be subject to accelerated vesting immediately prior to a change in control.


(7)	These phantom unit awards vest, subject to continued service, in equal installments on the first and second anniversaries of the vesting commencement date (January 1, 2016). In addition, these phantom unit awards may be subject to accelerated vesting immediately prior to a change in control.


(8)	These phantom unit awards vest, subject to continued service, in equal installments on the first and second anniversaries of the vesting commencement date (January 1, 2017, with respect to the awards granted on January 4, 2017, and January 1, 2018, with respect to the awards granted on December 29, 2017). In addition, these phantom unit awards may be

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subject to full or pro-rated accelerated vesting immediately prior to a change in control or upon a qualifying termination of service.

(9)

This phantom unit award vests subject to continued service, based on the achievement of performance, in pro-rated installments in connection with the sale or disposition of common units held by Insight Equity based on the ratio of common units sold or disposed of by Insight Equity as compared to the total number of common units held by Insight Equity immediately following the completion of our IPO. In addition, this phantom unit award may be subject to accelerated vesting immediately prior to a change in control. The number of units that have not vested, as shown in the table, assumes a payout of the unvested portion of the phantom unit award.

Option Exercises and Stock Vested

The following table provides information regarding the value realized by each of the named executive officers as a result of phantom units that vested during fiscal year 2017 :



Name	Number of Units Acquired on Vesting (#)	Value Realized on Vesting ($)(1)
Rick Shearer	25,387	186,980
Deborah Deibert	6,542	71,537
Warren Bonham	—	—
Nadya Kurani	2,357	29,015


(1)	Represents the product of the number of phantom units which vested and the closing price of our common units on the vesting date.

Potential Payments Upon a Termination or Change of Control

Employment Letters

Rick Shearer. The Amended Shearer Letter provides that if Mr. Shearer’s employment is terminated (i) by our general partner without “cause” (as defined in the Amended Shearer Letter), (ii) due to his death or disability, or (iii) due to our election not to extend the employment period when Mr. Shearer is willing and able, at the time of such election, to continue performing services to us in accordance with the terms of the Amended Shearer Letter, then, subject to Mr. Shearer’s timely execution and non-revocation of a general release of claims, Mr. Shearer will be entitled to receive an amount equal to twice his then-current annual base salary, payable in a cash lump sum amount within sixty days after the termination date.

Deborah Deibert. The Amended Deibert Letter provides that if Ms. Deibert’s employment is terminated by our general partner without “cause” (as defined in the Deibert Letter), then, subject to her timely execution and non-revocation of a release of claims, Ms. Deibert will be entitled to receive an amount equal to nine months of her then-current annual base salary, payable in a cash lump sum amount on the 60th day following her termination date.

Warren Bonham. Except with respect to his phantom unit awards (described below), Mr. Bonham is not eligible to receive any severance or change in control benefits.

Nadya Kurani. The Kurani Letter provides that if Ms. Kurani’s employment is terminated by our general partner without “cause” (as defined in the Kurani Letter), then, subject to her timely execution and non-revocation of a release of claims, Ms. Kurani will be entitled to receive an amount equal to six months of her then-current annual base salary, payable in a cash lump sum amount on the 60th day following her termination date.

Phantom Unit Awards

Phantom unit awards held by our named executive officers will accelerate and vest in full immediately prior to a change in control. In addition, all time-vesting phantom unit awards granted to Mr. Shearer and each time-vesting phantom unit award granted to Mses. Deibert and Kurani on or after January 4, 2017, provide for partial accelerated vesting upon a termination of service without “cause” (as defined in the applicable award agreement).

Summary of Potential Payments

The following table summarizes the payments that would be made to our named executive officers upon the occurrence of certain qualifying terminations of employment or a change in control event, assuming such named executive officer’s termination of employment occurred on December 31, 2017 , and, where relevant, that a change in control occurred on December 31, 2017 . Amounts shown in the table below do not include (1) accrued but unpaid salary and (2) other benefits earned or accrued by the named executive officer during his employment that are available to all salaried employees, such as accrued vacation.

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Name	Termination Due to Death or Disability ($)	Change in Control (No Termination) ($)	Qualifying Termination (Not in Connection with Change of Control) ($)	Qualifying Termination (In Connection with Change of Control) ($)
Rick Shearer
Cash Severance	1,050,000	—	1,050,000	1,050,000
Phantom Unit Acceleration	—	1,044,642	80,226	1,044,642
Total	1,050,000	1,044,642	1,130,226	2,094,642
Deborah Deibert
Cash Severance	—	—	220,508	220,508
Phantom Unit Acceleration	—	194,367	27,159	194,367
Total	—	194,367	247,667	414,875
Warren Bonham	—	—	—
Cash Severance	—	—	—	—
Phantom Unit Acceleration	—	1,342,519	—	1,342,519
Total	—	1,342,519	—	1,342,519
Nadya Kurani
Cash Severance	—	—	90,754	90,754
Phantom Unit Acceleration	—	88,078	13,580	88,078
Total	—	88,078	104,334	178,832

Pay Ratio Disclosure

As required by Section 953(b) of the Dodd-Frank Wall Street Reform and Consumer Protection Act, and Item 402(u) of Regulation S-K, we are providing the following information regarding the relationship of the annual total compensation of our employees and the annual total compensation of Rick Shearer, our Chief Executive Officer (our “CEO”). We consider the pay ratio specified below to be a reasonable estimate, calculated in a manner that is intended to be consistent with Item 402(u) of Regulation S-K.

For 2017, our last completed fiscal year:


•	the median of the annual total compensation of all of our employees (other than our CEO) was $51,789; and


•	the annual total compensation of our CEO, as reported in the Summary Compensation Table included in this Annual Report on Form 10-K, was $2,213,887 .

Based on this information, for 2017, the estimated ratio of our CEO’s annual total compensation was 43 times that of the median of the annual total compensation of all of our employees.

Determining the Median Employee

Employee Population

We determined that, as of December 31, 2017, our employee population consisted of 222 employees, including full-time, part-time and temporary employees .

Methodology for Determining Our Median Employee

To identify the median employee from our employee population, we selected base salary or wages plus overtime pay, as reflected in our payroll records as reported to the Internal Revenue Service on Form W-2 for 2017 as the most appropriate measure of compensation, which was consistently applied to all of our employees included in the calculation. In identifying the median employee, we annualized the compensation of all permanent employees who were new-hires in 2017.

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Compensation Measure and Annual Total Compensation of Median Employee

With respect to the annual total compensation of the median employee, we identified and calculated the elements of such employee’s compensation for 2017 in accordance with the requirements of Item 402(c)(2)(x) of Regulation S-K, resulting in annual total compensation of $51,789.

Director Compensation

On May 14, 2013, the board of directors of our general partner adopted, and in January 2015, it amended, the Emerge Energy Services LP Director Compensation Program (the “Director Plan”). Any non-employee director not affiliated with the partnership, our general partner, or certain Insight Equity affiliates is eligible to receive awards under the Director Plan.

Cash Compensation

Under the Director Plan, each eligible director is entitled to receive an annual cash retainer of $50,000. In addition, each committee chairperson receives a $10,000 annual cash retainer and each non-chair committee member receives a $2,500 annual cash retainer. Annual retainers are paid in cash quarterly in arrears, and are pro-rated to reflect any partial year of service.

Equity Compensation

Under the Director Plan, any eligible director who joins the board of directors of our general partner will receive a grant of restricted units covering a number of units having a value equal to $75,000 when he or she joins the board of directors of our general partner, pro-rated to reflect any partial year of service. Each restricted unit grant will vest in full on the anniversary of the closing of our IPO (May 14, 2013) immediately following the applicable grant date, subject to the eligible director’s continued service through the applicable vesting date. An eligible director serving on the board of directors of our general partner as of an anniversary of the closing of our IPO will be granted a restricted unit award valued at $75,000 on the applicable anniversary date, which will vest in full on the first anniversary of the grant date subject to continued service through the applicable vesting date.

2017 Director Compensation Table



Name (1)	Fees Earned in Cash ($)(2)	Stock Awards ($)(3)	Total ($)
Kevin Clark	62,500	74,995	137,495
Mark Gottfredson	52,500	74,995	127,495
Peter Jones	50,000	74,995	124,995
Francis J. Kelly, III	62,500	74,995	137,495


(1)	Only non-employee directors who are not affiliated with us, our general partner, or certain Insight Equity affiliates are eligible to receive cash and/or equity compensation pursuant to the Director Plan.


(2)	The amounts shown in this column include the annual retainer and any individual retainers for serving as the chair or non-chair committee member, in each case earned in 2017 .


(3)	The amounts shown in this column reflect the aggregate grant date fair value of restricted units awards granted in 2017 , calculated in accordance with financial accounting standards. The total number of restricted units outstanding as of the end of the 2017 fiscal year for each non-employee director was 5,760.

2018 Director Compensation Program

In December 2017, the board of directors of our general partner amended the Director Plan, effective as of January 1, 2018, in order to increase the value of the cash and equity compensation provided pursuant to the Director Plan. Specifically, under the amended Director Plan, each eligible director is entitled to receive an annual cash retainer of $52,500, each committee chairperson is entitled to receive an additional annual cash retainer of $10,500 and each non-chair committee member is entitled to receive an additional cash retainer of $2,625. Additionally, the value of awards of restricted units granted to (i) eligible directors who join the board of directors of our general partner and (ii) eligible directors serving on the board of directors of our general partner as of an anniversary of the closing of our IPO was increased to $78,750. The terms and conditions of the Director Plan otherwise remained unchanged.

Compensation Committee Report

As our general partner does not have a compensation committee, the board of directors of our general partner provides the oversight, administers, and makes decisions regarding our compensation policies and plans. Additionally, the board of directors of our general partner generally reviews and discusses the Compensation Discussion and Analysis with senior management of our general partner

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as a part of our governance practices. Based on this review and discussion, the board of directors of our general partner has directed that the Compensation Discussion and Analysis be included in this report for filing with the SEC.



Members of the Board of Directors of Emerge Energy Services GP LLC
Ted W. Beneski	Warren B. Bonham	Kevin Clark
Mark Gottfredson	Peter Jones	Francis J. Kelly, III
Eliot Kerlin	Rick Shearer	Victor L. Vescovo

Compensation Committee Interlocks and Insider Participation

As previously discussed, the board of directors of our general partner is not required to maintain, and does not maintain a compensation committee.

Messrs. Shearer and Bonham, who serve on the board of directors of our general partner, participate in their capacities as directors in the deliberations of the board of directors of our general partner concerning executive officer compensation. In addition, Mr. Shearer makes recommendations to the board of directors of our general partner regarding named executive officer compensation. Each of Messrs. Shearer and Bonham abstain from any decision regarding his own compensation.


ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDER MATTERS

The following table sets forth certain information regarding the beneficial ownership of units as of February 22, 2018 , (the “Ownership Reference Date”) by:


•	each person who is known to us to beneficially own 5% or more of such units to be outstanding;


•	our general partner;


•	each of the directors and named executive officers of our general partner; and


•	all of the directors and executive officers of our general partner as a group.

All information with respect to beneficial ownership has been furnished by the respective directors, officers or 5% or more unitholders as the case may be.

The amounts and percentage of units beneficially owned are reported on the basis of regulations of the SEC governing the determination of beneficial ownership of securities. Under the rules of the SEC, a person is deemed to be a “beneficial owner” of a security if that person has or shares “voting power,” which includes the power to vote or to direct the voting of such security, or “investment power,” which includes the power to dispose of or to direct the disposition of such security. In computing the number of common units beneficially owned by a person and the percentage ownership of that person, common units subject to options or warrants held by that person that are currently exercisable or exercisable within 60 days of the Ownership Reference Date, if any, are deemed outstanding, but are not deemed outstanding for computing the percentage ownership of any other person. Except as indicated by footnote, the persons named in the table below have sole voting and investment power with respect to all units shown as beneficially owned by them, subject to community property laws where applicable.

The percentage of units beneficially owned is based on a total 31,006,173 common units outstanding as of the Ownership Reference Date. Except as indicated by footnote, the persons named in the table below have sole voting and investment power with respect to all units shown as beneficially owned by them and their address is 5600 Clearfork Main Street, Suite 400, Fort Worth, Texas, 76109.

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Name of Beneficial Owner	Common Units Beneficially Owned	Percentage of Common Units to be Beneficially Owned
Insight Equity (1)	7,168,545	23.1%
Ted W. Beneski (2)	1,172,624	3.8%
Rick Shearer	245,130	*
Victor L. Vescovo	139,752	*
Warren B. Bonham	6,899	*
Deborah Deibert	15,744	*
Mark Gottfredson	100,080	*
Francis J. Kelly III	25,224	*
Kevin Clark	27,703	*
Eliot E. Kerlin, Jr.	2,408	*
Peter Jones	21,762	*
Nadya Kurani	5,976	*
All directors and officers as a group (11 persons)	8,931,847

An asterisk indicates that the person or entity owns less than one percent.

(1)

As described elsewhere in this prospectus, Ted W. Beneski and Victor L. Vescovo are the controlling equity owners of Insight Equity, which owns a controlling interest in Emerge Holdings, the entity which owns Emerge Energy Services GP, LLC. Messrs. Beneski and Vescovo, by virtue of being controlling equity owners of Insight Equity, may be deemed to beneficially own the units held by Insight Equity. Messrs. Beneski and Vescovo disclaim beneficial ownership of the units held by Insight Equity except to the extent of their pecuniary interest therein.


(2)	Amounts do not include 27,522 units for which Mr. Beneski disclaims beneficial ownership, which are held in irrevocable trust accounts in favor of his sons. Mr. Beneski is the trustee of each trust account.

Securities Authorized for Issuance under Equity Compensation Plans

The following table summarizes certain information regarding our equity compensation plans, including our LTIP, as of December 31, 2017 . Our LTIP allows for awards of options, phantom units, restricted units, unit awards, other unit awards and unit appreciation rights.



Plan Category	Number of Securities to be Issued Upon Exercise of Outstanding Options, Warrants and Rights	Weighted-Average Exercise Price of Outstanding Options, Warrants and Rights		Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans (Excluding Securities Reflected in Column(a))
	(a)(1)	(b)		(c)(2)
Equity compensation plans approved by security holders	333,821	$	—	1,063,548
Equity compensation plans not approved by security holders	—	—		—
Total	333,821	$	—	1,063,548


(1)	The amounts in column (a) of this table reflect only phantom units that have been granted (but not yet issued) under the LTIP. No unit options have been granted. Our LTIP was approved by our partners (general and limited) prior to our IPO. No value is shown in column (b) of the table, since the phantom units do not have an exercise, or strike, price.

(2)

The LTIP was adopted by the Emerge Energy Services GP LLC Board of Directors in connection with the closing of our IPO in May 2013, and provides for awards of options, restricted units, phantom units, distribution equivalent rights, substitute awards, unit appreciation rights, unit awards, profits interest units and other unit-based awards to be available for employees, consultants and directors of our general partner and any affiliates who perform services for Emerge Energy Services LP.

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ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Ownership Interests of Certain Executive Officers and Directors of Our General Partner

Insight Equity owns 7,168,545 common units representing a 23.1% limited partner interest in us, and is controlled by Ted Beneski and Victor Vescovo, the Chairman of the Board and each a member of our board of directors. Emerge Energy Services Holdings LLC is the sole member of our general partner. Emerge Energy Services Holdings LLC is controlled by Insight Equity.

Distributions and Payments to Our General Partner and Its Affiliates

The following table summarizes the distributions and payments to be made by us to our general partner and its affiliates in connection with our ongoing operation and liquidation. These distributions and payments were determined by and among affiliated entities and, consequently, are not the result of arm's-length negotiations.




Post-IPO Stage

Distributions of available cash to our general partner and its affiliates		We make cash distributions pro rata to the holders of our common units, including affiliates of our general partner, as the holders of an aggregate of 7,168,545 common units.

Payments to our general partner and its affiliates		Our general partner does not receive a management fee or other compensation for its management of us. Our general partner and its affiliates are reimbursed for expenses incurred on our behalf. Our partnership agreement provides that our general partner determines the amount of these expenses.

Withdrawal or removal of our general partner		If our general partner withdraws or is removed, its general partner interest and its incentive distribution rights will either be sold to the new general partner for cash or converted into common units, in each case for an amount equal to the fair market value of those interests.
Liquidation Stage

Liquidation		Upon our liquidation, the partners, including our general partner, will be entitled to receive liquidating distributions according to their particular capital account balances.

Other Agreements with Affiliates

We have various agreements with certain of our affiliates, as described below. These agreements have been negotiated among affiliated parties and, consequently, are not the result of arm's-length negotiations.

We entered into an administrative services agreement with Insight Management Company LLC pursuant to which Insight Management Company LLC provides specified general and administrative services to us and our subsidiaries from time to time. Under the terms of the agreement, we reimburse Insight Management Company LLC based on agreed upon-formulas on a monthly basis for the time and materials actually spent in performing general and administrative services on our behalf. In addition, Warren B. Bonham is considered to be an employee of Insight Management Company LLC. Mr. Bonham’s compensation for services provided to us are included in our normal periodic charges from our general partner for all of our employee costs. We expect that this administrative services agreement will remain in force until (i) the date we and Insight Management Company LLC mutually agree to terminate it; (ii) the final distribution in liquidation of us or our subsidiaries; or (iii) the date on which neither Insight Equity nor any of its affiliates own equity securities of us. We believe that the terms of the administrative services agreement are no less favorable to us than those generally available from unrelated third parties.

Procedures for Review, Approval and Ratification of Related-Person Transactions

Our code of business conduct and ethics provides that the board of directors of our general partner or its authorized committee periodically review all related person transactions that are required to be disclosed under SEC rules and, when appropriate, initially authorize or ratify all such transactions. In the event that the board of directors of our general partner or its authorized committee considers ratification of a related person transaction and determines not to so ratify, the code of business conduct and ethics provides that our management will make all reasonable efforts to cancel or annul the transaction.

The code of business conduct and ethics provides that, in determining whether or not to recommend the initial approval or ratification of a related person transaction, the board of directors of our general partner or its authorized committee should consider all of the relevant facts and circumstances available, including (if applicable) but not limited to: (i) whether there is an appropriate business justification for the transaction; (ii) the benefits that accrue to us as a result of the transaction; (iii) the terms available to unrelated third parties entering into similar transactions; (iv) the impact of the transaction on a director's independence (in the event the related person is a director, an immediate family member of a director or an entity in which a director or an immediately family

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member of a director is a partner, shareholder, member or executive officer); (v) the availability of other sources for comparable products or services; (vi) whether it is a single transaction or a series of ongoing, related transactions; and (vii) whether entering into the transaction would be consistent with the code of business conduct and ethics.

Further information required for this item is provided in Part I, Item 1. Business - Overview, Part III, Item 10. Directors, Executive Officers and Corporate Governance and Note 15, Related Party Transactions, included in the notes to the audited consolidated financial statements included in Part II, Item 8. Financial Statements and Supplementary Data.


ITEM 14.	PRINCIPAL ACCOUNTING FEES AND SERVICES

We have engaged BDO as our independent registered public accounting firm. The following table sets forth fees billed for professional serviced rendered by BDO to audit our annual financial statements and for other services in 2017 and 2016 , including out-of-pocket expenses billed.



	Year Ended December 31,
	2017		2016

	($ in thousands)
Audit fees (1)	$	840	$	1,434
Audit-related fees (2)	10		11
Total	$	850	$	1,445


(1)	Consists primarily of services provided in connection with the audit of the annual financial statements, audit of internal control over financial reporting, review of quarterly financial statements, services related to offering documents and advice on accounting policies.


(2)	Consists primarily of services performed related to the 401(k) audit.

Pursuant to the charter of the Audit Committee, the Audit Committee is responsible for the oversight of our accounting, reporting and financial practices. The Audit Committee is responsible for the appointment, compensation, retention and oversight of the work of our external auditors; the pre-approval of all audit and non-audit services to be provided, consistent with all applicable laws, to us by our external auditors; and the establishment of the fees and other compensation to be paid to our external auditors. The Audit Committee also oversees and directs our internal auditing program and reviews our internal controls.

The Audit Committee has adopted a policy for the pre-approval of audit and permitted non-audit services provided by our principal independent accountants. The policy requires that all services provided by BDO, including audit services, audit-related services, tax services and other services, must be pre-approved by the Audit Committee.

The Audit Committee reviews the external auditors' proposed scope and approach as well as the performance of the external auditors. It also has direct responsibility for resolution of and sole authority to resolve any disagreements between our management and our external auditors regarding financial reporting, regularly reviews with the external auditors any problems or difficulties the auditors encounter in the course of their audit work, and, at least annually, uses its reasonable efforts to obtain and review a report from the external auditors addressing the following (among other items):


•	the external auditors' internal quality-control procedures;


•	any material issues raised by the most recent internal quality-control review, or peer review, of the external auditors;


•	the independence of the external auditors;


•	the aggregate fees billed by the external auditors for each of the previous two fiscal years; and


•	the rotation of the external auditors' lead partner.

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PART IV


ITEM 15.	EXHIBITS AND FINANCIAL STATEMENT SCHEDULES


(a)(1).	Financial Statements . See “Index to Financial Statements” on page 61.


(a)(2).	Financial Statement Schedules . Other schedules are omitted because they are not required or applicable, or the required information is included in our consolidated financial statements or related notes.


(a)(3).	Exhibits . See “Index to Exhibits.”

Schedules other than those listed above are omitted because they are not required, not material, not applicable or the required information is shown in the financial statements or notes thereto.

Agreements attached or incorporated herein as exhibits to this report are included to provide investors with information regarding the terms and conditions of such agreements and are not intended to provide any other factual or disclosure information about Emerge Energy Services LP or the other parties to the agreements.

Such agreements may contain representations and warranties by the parties to the applicable agreement. These representations and warranties have been made solely for the benefit of the other parties to the applicable agreement and (i) should not in all instances be treated as categorical statements of fact, but rather as a way of allocating the risk to one of the parties if those statements prove to be inaccurate, (ii) have been qualified by disclosures that were made to the other party or parties in connection with the negotiation of the applicable agreement, which disclosures are not necessarily reflected in the agreement, (iii) may apply standards of materiality in a way that is different from what may be viewed as material to you or other investors and (iv) were made only as of the date of the applicable agreement or such other date or dates as may be specified in the agreement and are subject to more recent developments. Accordingly, the representations and warranties in such agreements may not describe the actual state of affairs as of the date they were made or at any other time.

ITEM 16. FORM 10-K SUMMARY

None

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

Date: March 1, 2018



	EMERGE ENERGY SERVICES LP

	By:	EMERGE ENERGY SERVICES GP LLC, its general partner

	By:	/s/ Rick Shearer
		Rick Shearer
		President, Chief Executive Officer and Director
		(Principal Executive Officer)

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons in their indicated capacities, which are with the general partner of the registrant, on the dates indicated.

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Signature	Title	Date

/s/ Rick Shearer	President, Chief Executive Officer and Director	March 1, 2018
Rick Shearer	(principal executive officer)

/s/ Deborah Deibert	Chief Financial Officer	March 1, 2018
Deborah Deibert	(principal financial officer)

/s/ Nadya Kurani	Chief Accounting Officer	March 1, 2018
Nadya Kurani	(principal accounting officer)

/s/ Ted W. Beneski	Chairman of the Board and	March 1, 2018
Ted W. Beneski	Director

/s/ Warren B. Bonham	Director	March 1, 2018
Warren B. Bonham

/s/ Kevin Clark	Director	March 1, 2018
Kevin Clark

/s/ Mark Gottfredson	Director	March 1, 2018
Mark Gottfredson

/s/ Peter Jones	Director	March 1, 2018
Peter Jones

/s/ Francis J. Kelly, III	Director	March 1, 2018
Francis J. Kelly, III

/s/ Eliot E. Kerlin, Jr.	Director	March 1, 2018
Eliot E. Kerlin, Jr.

/s/ Victor L. Vescovo	Director	March 1, 2018
Victor L. Vescovo

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INDEX TO EXHIBITS



Exhibit Number		Description

3.1		Certificate of Limited Partnership of Emerge Energy Services LP (incorporated by reference to Exhibit 3.1 to the Registrant’s Registration Statement on Form S-1, Registration No. 333-187487).

3.2		Amendment to Certificate of Limited Partnership of Emerge Energy Services LP (incorporated by reference to Exhibit 3.2 to the Registrant’s Registration Statement on Form S-1, Registration No. 333-187487).

3.3		First Amended and Restated Limited Partnership Agreement of Emerge Energy Services LP, dated as of May 14, 2013 (incorporated by reference to Exhibit 3.1 to the Registrant’s Current Report on Form 8-K, filed with the SEC on May 20, 2013).

3.4		Amendment No. 1 to the First Amended and Restated Agreement of Limited Partnership of Emerge Energy Services LP, dated August 15, 2016 (incorporated by reference to Exhibit 3.1 to the Registrant’s Current Report on Form 8-K, filed with the SEC on August 16, 2016).

3.5		Certificate of Limited Formation of Emerge Energy Services GP LLC (incorporated by reference to Exhibit 3.5 to the Registrant’s Registration Statement on Form S-1, Registration No. 333-187487).

3.6		Amendment to Certificate of Formation of Emerge Energy Services GP LLC (incorporated by reference to Exhibit 3.6 to the Registrant’s Registration Statement on Form S-1, Registration No. 333-187487).

3.7		Amended and Restated Limited Liability Company Agreement of Emerge Energy Services GP, LLC, dated as of May 14, 2013 (incorporated by reference to Exhibit 3.2 to the Registrant’s Current Report on Form 8-K, filed with the SEC on May 20, 2013).

4.1		Registration Rights Agreement, dated as of May 14, 2013, by and among Emerge Energy Services LP, AEC Resources LLC, Ted W. Beneski, Superior Silica Resources LLC, Kayne Anderson Development Company and LBC Sub V, LLC (incorporated by reference to Exhibit 10.5 to the Registrant’s Current Report on Form 8-K, filed with the SEC on May 20, 2013).

4.2		Registration Rights Agreement, dated August 15, 2016, by and between Emerge Energy Services LP and Sig Strategic Investments, LLLP (incorporated by reference to Exhibit 10.2 to the Registrant’s Current Report on Form 8-K, filed with the SEC on August 16, 2016).

4.3		Registration Rights Agreement, dated January 5, 2018, by and between Emerge Energy Services LP, Mezzanine Partners III, L.P., AP Mezzanine Partners III, L.P., EES Offshore, LLC and OC II AIV II LP (incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K, filed with the SEC on January 8, 2018).

10.1		Second Amended and Restated Revolving Credit and Security Agreement, dated as of January 5, 2018, among Emerge Energy Services LP, as parent guarantor, the Borrowers party thereto, PNC Bank, National Association, as administrative agent and collateral agent, and the Lenders party thereto (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K, filed with the SEC on January 8, 2018).

10.2		Second Lien Note Purchase Agreement, dated as of January 5, 2018, between Emerge Energy Services LP, Emerge Energy Services Operating LLC, as issuers, and HPS Investment Partners, LLC as notes agent and collateral agent (incorporated by reference to Exhibit 10.2 to the Registrant’s Current Report on Form 8-K, filed with the SEC on January 8, 2018).

10.3		Administrative Services Agreement, dated as of May 14, 2013, by and among Emerge Energy Services LP, Emerge Energy Services GP LLC and Insight Equity Management Company LLC (incorporated by reference to Exhibit 10.6 to the Registrant’s Current Report on Form 8-K, filed with the SEC on May 20, 2013).

10.4		Emerge Energy Services LP 2013 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.3 to the Registrant’s Current Report on Form 8-K, filed with the SEC on May 20, 2013).

10.5		Emerge Energy Services LP Director Compensation Program (incorporated by reference to Exhibit 10.4 to the Registrant’s Annual report on Form 10-K, filed with the SEC on March 5, 2015).

10.6		Form of Emerge Energy Services LP 2013 Long-Term Incentive Plan Phantom Unit Agreement (Performance-Vesting Agreement) (incorporated by reference to Exhibit 10.7 to the Registrant’s Current Report on Form 8-K, filed with the SEC on May 20, 2013).

10.7		Form of Emerge Energy Services LP 2013 Long-Term Incentive Plan Phantom Unit Agreement (Time-Vesting Agreement) (incorporated by reference to Exhibit 10.8 to the Registrant’s Current Report on Form 8-K, filed with the SEC on May 20, 2013).

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Exhibit Number		Description
10.8		Amended Employment Letter, dated May 29, 2013, between Emerge Energy Services GP LLC and Rick Shearer (incorporated by reference to Exhibit 10.3 to the Registrant’s Current Report on Form 8-K, filed with the SEC on June 4, 2013).

10.9 †		Sand Supply Agreement, dated as of May 31, 2011, between Superior Silica Sands LLC and Schlumberger Technology Corporation (incorporated by reference to Exhibit 10.5 to the Registrant’s Registration Statement on Form S-1, Registration No. 333-187487).

10.10 †		Sand Supply Agreement, dated as of March 31, 2011, between Superior Silica Sands LLC and BJ Services Company, U.S.A (incorporated by reference to Exhibit 10.6 to the Registrant’s Registration Statement on Form S-1, Registration No. 333-187487).

10.11 †		Amendment to Sand Supply Agreement, dated as of November 15, 2012 between Superior Silica Sands LLC and Schlumberger Technology Corporation (incorporated by reference to Exhibit 10.11 to the Registrant’s Registration Statement on Form S-1, Registration No. 333-187487).

10.12 †		Second Amendment to Sand Supply Agreement, dated as of June 10, 2014, between Superior Silica Sands LLC and Schlumberger Technology Corporation (incorporated by reference to Exhibit 10.1 to the Registrant’s Quarterly Report on Form 10-Q, filed with the SEC on August 8, 2014).

10.13 †		Memorandum of Understanding, dated May 9, 2012, between Canadian National Railway Company and Superior Silica Sands LLC (incorporated by reference to Exhibit 10.9 to the Registrant’s Registration Statement on Form S-1, Registration No. 333-187487).

10.14 †		Wet Sand Services Agreement, dated April 7, 2011, by and between Superior Silica Sands LLC and Fred Weber, Inc. (incorporated by reference to Exhibit 10.10 to the Registrant’s Registration Statement on Form S-1, Registration No. 333-187487).

10.15 †		Sand Supply Agreement, dated as of May 19, 2017, between Superior Silica Sands LLC and Liberty Oilfield Services, LLC (incorporated by reference to Exhibit 10.1 to the Registrant’s Quarterly Report on Form 10-Q, dated August 4, 2017.

10.16 †		Sand Supply Agreement, dated as of July 19, 2917, between Superior Silica Sands LLC and EP Energy E&P Company, L.P. (incorporated by reference to Exhibit 10.2 to the Registrant’s Quarterly Report on Form 10-Q, dated August 4, 2017).

10.17 †		Amended and Restated Master Supply Agreement, dated December 22, 2015, between Superior Silica Sands LLC and Performance Technologies, LLC LLC (incorporated by reference to Exhibit 10.24 to the Registrant’s Annual Report on Form 10-K, filed with the SEC on February 29, 2016).

10.18 †		Purchase Option Agreement, dated December 22, 2015, between Superior Silica Sands LLC and Performance Technologies, LLC (incorporated by reference to Exhibit 10.25 to the Registrant’s Annual Report on Form 10-K, filed with the SEC on February 29, 2016).

10.19		Warrant to Purchase Common Units Representing Limited Partner Interests in Emerge Energy Services LP, dated June 2, 2016, by and between Emerge Energy Services LP and Trinity Industries Leasing Company and Schedule of Substantially Identical Warrants Omitted Pursuant to Instruction 2 to Item 601 of Regulation S-K (incorporated by reference to Exhibit 10.8 to the Registrant’s Quarterly Report on Form 10-Q, filed with the SEC on September 12, 2016).

10.20		Unsecured Promissory Note of Superior Silica Sands LLC, dated June 2, 2016 (incorporated by reference to Exhibit 10.9 to the Registrant’s Quarterly Report on Form 10-Q, filed with the SEC on September 9, 2016).

10.21		Amendment to Amended Employment Letter, dated April 15, 2016, by and between Emerge Energy Services GP LLC and Rick Shearer (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K, filed with the SEC on April 15, 2016).

10.22		Warrant to Purchase Common Units, dated August 15, 2016, by and between Emerge Energy Services LP and SIG Strategic Investments, LLLP (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K, filed with the SEC on August 16, 2016).

10.23 †		Second Lien Term Loan Agreement, dated April 12, 2017, among Emerge Energy Services Operating LLC and Superior Silica Sands LLC, the Borrowers party and U.S. Bank National Association as disbursing agent and collateral agent (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K, filed with the SEC on April 17, 2017).

10.24 #		Second Amendment to Amended Employment Letter, dated November 2, 2016, by and between Emerge Energy Services GP LLC and Rick Shearer (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K, filed with the SEC on November 3, 2016).

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Exhibit Number		Description

21.1*		List of Subsidiaries of Emerge Energy Services LP.

23.1*		Consent of BDO USA, LLP.

23.2*		Consent of Cooper Engineering Company, Inc.

23.3*		Consent of Westward Environmental, Inc.

31.1*		Certification of Chief Executive Officer under Section 302 of the Sarbanes-Oxley Act of 2002.

31.2*		Certification of Chief Financial Officer under Section 302 of the Sarbanes-Oxley Act of 2002.

32.1*		Certification of Chief Executive Officer under Section 906 of the Sarbanes-Oxley Act of 2002.

32.2*		Certification of Chief Financial Officer under Section 906 of the Sarbanes-Oxley Act of 2002.

95.1*		Mine Safety Disclosure Exhibit.

101*		Interactive Data Files - XBRL.

* Filed herewith (or furnished in the case of Exhibits 32.1 and 32.2).

# Compensatory plan or arrangement.


†	Certain portions have been omitted pursuant to a confidential treatment request. Omitted information has been separately filed with the Securities and Exchange Commission.